High napthenic content marine fuel compositions

ABSTRACT

Marine diesel fuel/fuel blending component compositions and fuel oil/fuel blending component compositions are provided that are derived from crude oils having high naphthenes to aromatics volume and/or weight ratios and a low sulfur content. In addition to having a high naphthenes to aromatics ratio, a low sulfur content, and a low but substantial content of aromatics, such fuels and/or fuel blending components can have a reduced or minimized carbon intensity relative to fuels derived from conventional sources. The unexpected ratio of naphthenes to aromatics contributes to the fuels and/or fuel blending components further having additional unexpected properties, including low density, low kinematic viscosity, and/or high energy density.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 63/028,695, filed on May 22, 2020, the entire contents of which are incorporated herein by reference.

FIELD

This disclosure relates to marine fuel compositions having high naphthenic content and low aromatic content, such as marine fuel oils, marine gas oils, and methods for forming such fuel compositions.

BACKGROUND

Regulatory bodies continue to mandate decreasing sulfur levels in transportation fuels to reduce SOx emissions from fuel combustion. One such example is the International Maritime Organization (IMO) mandate to reduce sulfur in marine fuel used in the open ocean to 5000 mg/kg or less, which took effect January 2020. Prior to this mandate (“IMO2020”) taking effect, marine fuels used near coastal areas known as Emission Control Areas or ECAs were already required to have 1000 mg/kg or less sulfur, or in select areas 500 mg/kg or less sulfur. Inland waterways such as lakes or rivers can require even lower sulfur levels in line with on-road diesel, such as 10 mg/kg or less, or 15 mg/kg or less.

Expanding mandates create a need for more volume of low sulfur fuels for consumption by marine vessels. Typically the lower sulfur marine fuels available on the market, especially the fuels with sulfur level at or below 1000 mg/kg, have been distillates. These distillate molecules are in high demand, as they are also needed for on-road use and other applications such as home heating. Typically the production of lower sulfur fuels, especially for coastal ECAs, requires desulfurization or blending with desulfurized components due to straight-run material distilled from crude oil having higher sulfur levels.

In addition to being energy intensive, the desulfurization process increases the carbon intensity associated with marine fuel manufacturing, as the heat for the desulfurization process is typically provided by combustion of hydrocarbons. It would be desirable to develop compositions suitable for use as low sulfur marine fuels while also reducing or minimizing the amount of refinery processing associated with production of a marine fuel.

U.S. Pat. No. 8,999,011 describes vacuum gas oil fractions that can be used in fuel compositions such as fuel oils.

U.S. Patent Application Publication 2017/0183575 describes fuel compositions formed during hydroprocessing of deasphalted oils for lubricant production.

U.S. Patent Application Publication 2019/0185772 describes various marine fuel compositions, including fuel oils formed using hydrotreated vacuum resid fractions.

An article titled “Catalytic Solutions for Processing Shale Oils in the FCC” (www.digitalrefining.com, April 2014) describes bottoms fractions derived from shale oils extracted from various sources, along with methods for processing the bottoms fractions.

A journal article by Drushel and Miller titled “Spectrophotometric Determination of Aliphatic Sulfides in Crude Petroleum Oils and Their Chromatographic Fractions” (Anal. Chem. 1955, 27, 4, 495-501) describes methods for determining the quantity of aliphatic sulfur in a hydrocarbon fraction.

A journal article by White et al. entitled “Determination of Basic Nitrogen in Oils” (Anal. Chem. 1953, 25, 3, 426-432) describes determining the basic nitrogen content in a hydrocarbon sample.

U.S. Pat. No. 9,803,152 describes determination of the Bureau of Mines Correlation Index (BMCI) of a petroleum fraction.

SUMMARY

In various aspects, marine fuels and/or fuel blending components are formed at least in part from fractions derived from selected crude oils having a low sulfur content and a high naphthenes to aromatics weight ratio and/or volume ratio. The fractions derived from the selected crude oils can have a low sulfur content, a high naphthenes to aromatics weight ratio, and a low but substantial content of aromatics. The fractions can be used as fuels or fuel blending components after fractionation and/or after blending with one or more other fractions, such as renewable fractions. For fractions that are not exposed to hydroprocessing conditions, the fractions can have characteristics that indicate a lack of hydroprocessing, such as a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more and/or a weight ratio of basic nitrogen to total nitrogen of 0.2 or more.

In one aspect of the instant disclosure, provided is a vacuum gas oil boiling range fraction comprising a T10 distillation point of 350° C. or more, a T90 distillation point of 525° C. or less, a density at 15° C. of 890 kg/m³ or less, a sulfur content of 0.3 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 790 or less.

In another aspect of the instant disclosure, provided is a fuel composition comprising 10 vol % to 45 vol % of a distillate fraction and 55 vol % to 90 vol % of an vacuum gas oil fraction, wherein the vacuum gas oil fraction comprises a T90 distillation point of 525° C. or less, a density at 15° C. of 890 kg/m³ or less, a sulfur content of 0.3 wt % or less, and a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more.

In another aspect of the instant disclosure, provided is a vacuum resid boiling range fraction comprising a T10 distillation point of 500° C. or more, a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.4 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 790 or less.

In another aspect of the instant disclosure, provided is a fuel composition comprising: 25 vol % to 75 vol % of a vacuum resid fraction and 25 vol % to 75 vol % of a distillate fraction, a cracked distillate fraction, or a combination thereof, wherein the fuel composition comprises a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.5 wt % or less, a CCAI of 820 or less, and a pour point of 30° C. or less, and wherein the vacuum resid fraction comprises a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.4 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 790 or less.

In another aspect of the instant disclosure, provided is a method for forming a fuel composition, comprising: fractionating a whole crude or crude fraction to form a vacuum gas oil fraction comprising a T10 distillation point of 350° C. or more, a T90 distillation point of 525° C. or less, a density at 15° C. of 890 kg/m³ or less, a sulfur content of 0.3 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 790 or less.

In another aspect of the instant disclosure, provided is a marine fuel composition comprising a T10 distillation point of 150° C. to 230° C., a T90 distillation point of 350° C. to 425° C., a kinematic viscosity at 40° C. of 2.0 cSt to 4.0 cSt, a sulfur content of 0.07 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a cetane index of 45 or more.

In yet another aspect of the instant disclosure, provided is a method for forming a residual fuel or fuel blending product comprising: blending 25 vol % to 75 vol % of a vacuum resid fraction and 25 vol % to 75 vol % of a distillate fraction, a cracked distillate fraction, or a combination thereof, wherein the fuel composition comprises a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.5 wt % or less, a CCAI of 820 or less, and a pour point of 30° C. or less, and wherein the vacuum resid fraction comprises a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.35 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 780 or less.

In still yet another aspect of the instant disclosure, provided is a method for forming a fuel composition, comprising: fractionating a whole crude or crude fraction to form a fraction comprising a T10 distillation point of 150° C. to 230° C., a T90 distillation point of 350° C. to 425° C., a kinematic viscosity at 40° C. of 2.0 cSt to 4.0 cSt, a sulfur content of 0.07 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a cetane index of 49 or more.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows compositional information for various crude oils.

FIG. 2 shows compositional information for various crude oils.

FIG. 3 shows modeled compositional values for atmospheric resid fractions.

FIG. 4 shows modeled compositional values for atmospheric resid fractions.

FIG. 5 shows modeled compositional values for atmospheric resid fractions.

FIG. 6 shows modeled compositional values for atmospheric resid fractions.

FIG. 7 shows measured and modeled compositional values for distillate fractions.

FIG. 8 shows measured and modeled compositional values for distillate fractions.

FIG. 9 shows measured and modeled compositional values for distillate fractions.

FIG. 10 shows measured and modeled compositional values for distillate fractions.

FIG. 11 shows measured and modeled compositional values for distillate fractions.

FIG. 12 shows measured compositional values for vacuum gas oil fractions.

FIG. 13 shows measured compositional values for vacuum gas oil fractions.

FIG. 14 shows modeled compositional values for vacuum gas oil fractions.

FIG. 15 shows modeled compositional values for vacuum gas oil fractions.

FIG. 16 shows modeled compositional values for vacuum resid fractions.

FIG. 17 shows modeling results for blending of fuel oils (i.e., modeled atmospheric resids) from FIG. 3 with the ULSD fraction.

FIG. 18 shows modeled values for selected high naphthene to aromatic ratio vacuum resid (“VR”) fractions.

FIG. 19 shows additional modeled values for selected high naphthene to aromatic ratio vacuum resid (“VR”) fractions.

DETAILED DESCRIPTION

In various aspects, marine diesel fuel/fuel blending component compositions and fuel oil/fuel blending component compositions are provided that include at least a portion of a crude oil fraction having a low sulfur content and high weight ratio and/or volume ratio of naphthenes to aromatics. It has been discovered that such fractions can be used to form fuels and/or fuel blending components that have a reduced or minimized carbon intensity relative to fuels derived from conventional sources. This reduced carbon intensity is provided based in part on a combination of an unexpectedly low sulfur content, an unexpectedly high weight ratio and/or volume ratio of naphthenes to aromatics, and a low but substantial content of aromatics in the fractions derived from such crude oils. The unexpected ratio of naphthenes to aromatics contributes to the fractions further having additional unexpected properties, including low density, low kinematic viscosity, and/or high energy density. Based on this unexpected combination of features, the fractions can be suitable for production of low carbon intensity fuels and/or fuel blending components with only a reduced or minimized amount of processing. For example, distillation of a select crude oil feed into appropriate fractions can be sufficient to form some fractions that are directly usable as marine fuel and/or fuel blending components, without needing to expose the fraction(s) to hydroprocessing conditions.

By reducing, minimizing, and/or eliminating processing at various stages in the life cycle of a fuel and/or fuel blending component, a fuel or fuel blending component can be formed that has a reduced carbon intensity. In other words, due to this reduced or minimized processing, the net amount of CO₂ generation that is required to produce a fuel or fuel blending component and then use the resulting fuel can be reduced.

As an example, some selected shale oil fractions including a resid or bottoms portion of a shale crude can be used for production of low carbon intensity, low sulfur marine fuels, such as low sulfur fuel oils. In some aspects involving an atmospheric resid fraction, a reduced or minimized amount of processing is needed to form a marine fuel oil. This is due in part to the low density and kinematic viscosity of the atmospheric resid fraction, so that the specifications for density and kinematic viscosity can be satisfied without addition of a distillate boiling range flux. Because a distillate boiling range flux is not needed, a fuel oil formed from a low carbon intensity atmospheric resid fraction can have an unexpectedly high flash point. Additionally, hydroprocessing of the atmospheric resid fraction can be reduced, minimized, or eliminated due to the low sulfur content. By reducing or minimizing processing of the atmospheric resid fraction, in combination with reducing or minimizing the amount of blending with higher carbon intensity components, a low carbon intensity fuel oil can be formed. Such fuels can provide still further advantages based on the low nitrogen content, low n-heptane insolubles content, and/or low content of micro carbon residue (MCR).

As another example, various blending components can be added to an atmospheric or vacuum resid fraction to form low carbon intensity marine fuels with unexpectedly high ratios of naphthenes to aromatics and unexpectedly low sulfur contents. In some aspects, at least a portion of the blend components can correspond to renewable blending components.

As yet another example, distillate fractions can be used can be used to form low carbon intensity marine distillate fuels with unexpectedly high ratios of naphthenes to aromatics and unexpectedly low sulfur contents. In some aspects, at least a portion of the blend components can correspond to renewable blend components.

Recent legislation and/or regulations have created Emission Control Areas in the coastal waters of various countries. In such Emission Control Areas, marine vessels are constrained to have emissions that correspond to the expected emissions from combustion of a low sulfur fuel oil having a sulfur content of roughly 0.1 wt % or less. Similarly, recent regulations have more generally set a global sulfur limit for fuel oil of 0.5 wt % or less. Currently, relatively few types of blend stocks are commercially available that satisfy this requirement. In part, the limited availability of suitable blend stocks for low sulfur fuel oils is based on the relatively high sulfur content of the traditional feeds used for fuel oil production. The typical vacuum resid feeds used for fuel oil production often have sulfur contents of 2 wt % or more. Performing sufficient processing on such feeds to generate a low (or ultra-low) sulfur fuel oil is generally not economically favorable. Additionally, such processing can substantially increase the carbon intensity of the resulting fuel.

Crude oil production from shale oil formations has increased significantly in the past 10 years. The properties of shale oil can vary widely between shale oil formations and even within a shale oil formation. It has been unexpectedly discovered that certain types of shale oil fractions, having a high naphthene to aromatics ratio and a low sulfur content, can be beneficial for forming fuel and/or fuel blending products with reduced carbon intensity.

Due to the low sulfur content, in some aspects the selected crude oil fractions can be suitable for incorporation into low sulfur fuel oils or ultra low sulfur fuel oils with only minimal processing other than distillation. In some aspects, a crude oil fraction that is incorporated into a fuel or fuel blending product can correspond to a crude oil fraction that has not been hydroprocessed and/or that has not been cracked. In this discussion, a non-hydroprocessed fraction is defined as a fraction that has not been exposed to more than 10 psia of hydrogen in the presence of a catalyst comprising a Group VI metal, a Group VIII metal, a catalyst comprising a zeolitic framework, or a combination thereof. In this discussion, a non-cracked fraction is defined as a fraction that has not been exposed to a temperature of 400° C. or more. Optionally, hydroprocessing can be performed on a shale oil fraction to facilitate use in an ultra-low sulfur fuel.

The lower carbon intensity of a fuel containing at least a portion of a high naphthenes to aromatic ratio, low sulfur fraction can be realized by using a fuel containing at least a portion of such a high naphthenes to aromatic ratio, low sulfur fraction in any convenient type of combustion powered device. In some aspects, a fuel containing at least a portion of a high naphthenes to aromatic ratio, low sulfur fraction can be used as fuel for a combustion engine in a ground transportation vehicle, a marine vessel, or another convenient type of vehicle. Still other types of combustion devices can include generators, furnaces, and other combustion devices that are used to provide heat or power.

In addition to low sulfur content, the select crude oil fractions with a high ratio of naphthenes to aromatics can also have low nitrogen content and low micro carbon residue content. These features can further reduce emissions associated with the shale oil fractions. For example, the low micro carbon residue content and/or the low aromatics content can reduce or minimize the amount of soot produced during combustion of the shale oil fractions. The low nitrogen content can reduce or minimize the potential for formation of NOx species during combustion of the shale oil fractions.

In various aspects, a select crude oil fraction can be included as part of a fuel or fuel blending product. For convenience, unless otherwise specified, it is understood that references to incorporation of a crude oil fraction into a fuel also include incorporation of such a fraction into a fuel blending product.

Definitions

All numerical values within the detailed description and the claims herein are modified by “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.

In this discussion, a shale crude oil is defined as a petroleum product with a final boiling point greater than 550° C., or greater than 600° C., that is extracted from a shale petroleum source. A shale oil fraction is defined as a boiling range fraction derived from a shale crude oil.

Unless otherwise specified, distillation points and boiling points can be determined according to ASTM D2887. For samples that are not susceptible to characterization using ASTM D2887, D7169 can be used. It is noted that still other methods of boiling point characterization may be provided in the examples. The values generated by such other methods are believed to be indicative of the values that would be obtained under ASTM D2887 and/or D7169. In this discussion, the distillate boiling range is defined as 170° C. to 566° C. A distillate boiling range fraction is defined as a fraction having a T10 distillation point of 170° C. or more and a T90 distillation point of 566° C. or less. An atmospheric resid is defined as a bottoms fraction having a T10 distillation point of 149° C. or higher, or 350° C. or higher. In some aspects, an atmospheric resid can have a T90 distillation point of 550° C. or more, or 565° C. or more. A vacuum gas oil boiling range fraction can have a T10 distillation point of 350° C. or higher and a T90 distillation point of 535° C. or less. A vacuum resid is defined as a bottoms fraction having a T10 distillation point of 500° C. or higher, or 565° C. or higher. A resid-containing fraction is defined as a fraction that includes bottoms, and therefore can contain a vacuum resid and/or an atmospheric resid. It is noted that the definitions for distillate boiling range fraction, atmospheric resid, and vacuum resid are based on boiling point only. Thus, a distillate boiling range fraction or a resid-containing fraction (such as an atmospheric resid-containing fraction or a vacuum resid-containing fraction) can include components that did not pass through a distillation tower or other separation stage based on boiling point. A shale oil distillate boiling range fraction is defined as a shale oil fraction corresponding to the distillate boiling range. A shale oil atmospheric resid is defined as a shale oil bottoms fraction corresponding to an atmospheric resid. A shale oil vacuum resid is defined as a shale oil bottoms fraction corresponding to a vacuum resid.

In this discussion, a hydroprocessed fraction refers to a hydrocarbon fraction and/or hydrocarbonaceous fraction that has been exposed to a catalyst having hydroprocessing activity in the presence of 300 kPa-a or more of hydrogen at a temperature of 200° C. or more. Examples of hydroprocessed fractions include hydroprocessed distillate fractions (i.e., a hydroprocessed fraction having the distillate boiling range) and hydroprocessed resid fractions (i.e., a hydroprocessed fraction having the resid boiling range). It is noted that a hydroprocessed fraction derived from a biological source, such as hydrotreated vegetable oil, can correspond to a hydroprocessed distillate fraction and/or a hydroprocessed resid fraction, depending on the boiling range of the hydroprocessed fraction.

In this discussion, a cracked fraction refers to a hydrocarbon and/or hydrocarbonaceous fraction that is derived from the effluent of a thermal cracking or catalytic cracking process. A cracked distillate fraction (having the distillate boiling range), such as a light cycle oil from a fluid catalytic cracking process, is an example of a cracked fraction.

In this discussion, renewable blending components can correspond to renewable distillate and/or vacuum gas oil and/or vacuum resid boiling range components that are renewable based on one or more attributes. Some renewable blending components can correspond to components that are renewable based on being of biological origin. Examples of renewable blending components of biological origin can include, but are not limited to, fatty acid methyl esters (FAME), fatty acid alkyl esters, biodiesel, biomethanol, biologically derived dimethyl ether, oxymethylene ether, liquid derived from biomass, pyrolysis products from pyrolysis of biomass, products from gasification of biomass, and hydrotreated vegetable oil. Other renewable blending components can correspond to components that are renewable based on being extracted from a reservoir using renewable energy, such as petroleum extracted from a reservoir using an extraction method that is powered by renewable energy, such as electricity generated by solar, wind, or hydroelectric power. Still other renewable blending components can correspond to blending components that are made or processed using renewable energy, such as Fischer-Tropsch distillate that is formed using processes that are powered by renewable energy, or conventional petroleum distillate that is hydroprocessed/otherwise refinery processed using reactors that are powered by renewable energy. Yet other renewable blending components can correspond to fuel blending components formed from recycling and/or processing of municipal solid waste, or another source of carbon-containing waste. An example of processing of waste is pyrolysis and/or gasification of waste, such as or gasification of municipal solid waste.

More generally, high naphthenes to aromatics ratio, low sulfur content fractions (such as a selected shale oil fraction) as described herein may be blended with any of the following and any combination thereof in order to form a fuel and/or fuel blending component; low sulfur diesel (sulfur content of less than 500 wppm), ultra low sulfur diesel (sulfur content <10 or <15 ppmw), low sulfur gas oil, ultra low sulfur gasoil, low sulfur kerosene, ultra low sulfur kerosene, hydrotreated straight run diesel, hydrotreated straight run gas oil, hydrotreated straight run kerosene, hydrotreated cycle oil, hydrotreated thermally cracked diesel, hydrotreated thermally cracked gas oil, hydrotreated thermally cracked kerosene, hydrotreated coker diesel, hydrotreated coker gas oil, hydrotreated coker kerosene, hydrocracker diesel, hydrocracker gas oil, hydrocracker kerosene, gas-to-liquid diesel, gas-to-liquid kerosene, gas-to-liquid vacuum gas oil, hydrotreated vegetable oil, fatty acid methyl esters, non-hydrotreated straight-run diesel, non-hydrotreated straight-run kerosene, non-hydrotreated straight-run gas oil and any distillates derived from low sulfur crude slates, gas-to-liquid wax, and other gas-to-liquid hydrocarbons, non-hydrotreated cycle oil, non-hydrotreated fluid catalytic cracking slurry oil, non-hydrotreated pyrolysis gas oil, non-hydrotreated cracked light gas oil, non-hydrotreated cracked heavy gas oil, non-hydrotreated pyrolysis light gas oil, non-hydrotreated pyrolysis heavy gas oil, non-hydrotreated pyrolysis distillate (e.g., kerosene and/or diesel), non-hydrotreated pyrolysis residue, non-hydrotreated thermally cracked residue, non-hydrotreated thermally cracked heavy distillate, non-hydrotreated coker heavy distillates, non-hydrotreated vacuum gas oil, non-hydrotreated coker diesel, non-hydrotreated coker gasoil, non-hydrotreated coker vacuum gas oil, non-hydrotreated thermally cracked vacuum gas oil, non-hydrotreated thermally cracked diesel, non-hydrotreated thermally cracked gas oil, hydrotreated fats or oils such as hydrotreated vegetable oil, hydrotreated tall oil, etc., fatty acid methyl ester, Group 1 slack waxes, lube oil aromatic extracts, deasphalted oil, atmospheric tower bottoms, vacuum tower bottoms, steam cracker tar, any residue materials derived from low sulfur crude slates, LSFO, RSFO, other LSFO/RSFO blend stocks.

Additionally, as needed, fuel or fuel blending component fractions generated from high naphthene to aromatics ratio, low sulfur fractions and/or other blendstocks may be additized with additives such as pour point improver, cetane improver, lubricity improver, etc. to improve properties and/or meet local specifications.

With regard to characterizing properties of distillate boiling range fractions and/or blends of such fractions with other components to form distillate fuels, a variety of methods can be used. Density of a blend at 15° C. (kg/m³) can be determined according ASTM D4052. Sulfur (in wppm) can be determined according to ASTM D2622. Nitrogen (in wppm) can be determined according to ASTM D4629. Kinematic viscosity at either 40° C. or 50° C. (in cSt) can be determined according to ASTM D445. Cetane index for a distillate fraction or a marine gas oil can be calculated according to ASTM D4737, Procedure A. Cloud Point (in ° C.) can be determined according to D5773. Pour Point (in ° C.) can be determined according to D5949. Derived cetane number can be determined according to ASTM D7668. Acid number can be determined according to ASTM D664.

For various marine fuels, density (in kg/m) can be determined according to ISO 3675. For marine fuel oils, sulfur (in wppm) can be determined according to ISO 8754. For marine fuel oils, kinematic viscosity at 50° C. (in cSt) can be determined according ISO 3104. For marine fuel oils, pour point can be determined according to ISO 3016. For marine fuel oils, sediment can be determined according to ISO 10307-2. CCAI (calculated carbon aromaticity index) can be determined according Equation F.1 in ISO 8217:2017. Energy content can be determined according to the methodology in ISO 8217:2017 Annex H. Micro carbon residue content can be determined according to ASTM D4530. The content of n-heptane insolubles can be determined according to ASTM D3279. Flash point can be determined according to ASTM D93. The metals content can be determined according to ASTM D8056. Nitrogen can be determined according to ASTM D4629 for lower concentrations and ASTM D5762 for higher concentrations, as appropriate. Carbon and Hydrogen content can be determined according to ASTM D5291. Data related to aliphatic sulfur was generated using methods similar to that described in the article by Drushel and Miller referenced in the Background section of the instant application and is herein incorporated by reference for such methods. Data related to basic nitrogen content was generated using methods similar to the article by White et al. referenced in the Background section of the instant application and is herein incorporated by reference for such methods. Data related to Bureau of Mines Correlation Index (BMCI) was generated using methods similar to that described in U.S. Pat. No. 9,803,152 referenced in the Background section of the instant application and is herein incorporated by reference for such method.

With regard to determining paraffin, naphthene, and aromatics contents, supercritical fluid chromatography (SFC) was used. The characterization was performed using a commercial supercritical fluid chromatograph system, and the methodology represents an expansion on the methodology described in ASTM D5186 to allow for separate characterization of paraffins and naphthenes. The expansion on the ASTM D5186 methodology was enabled by using additional separation columns, to allow for resolution of naphthenes and paraffins. The system was equipped with the following components: a high pressure pump for delivery of supercritical carbon dioxide mobile phase; temperature controlled column oven; auto-sampler with high pressure liquid injection valve for delivery of sample material into mobile phase; flame ionization detector; mobile phase splitter (low dead volume tee); back pressure regulator to keep the CO₂ in supercritical state; and a computer and data system for control of components and recording of data signal. For analysis, approximately 75 milligrams of sample was diluted in 2 milliliters of toluene and loaded in standard septum cap autosampler vials. The sample was introduced based via the high pressure sampling valve. The SFC separation was performed using multiple commercial silica packed columns (5 micron with either 60 or 30 angstrom pores) connected in series (250 mm in length either 2 mm or 4 mm ID). Column temperature was held typically at 35 or 40° C. For analysis, the head pressure of columns was typically 250 bar. Liquid CO₂ flow rates were typically 0.3 ml/minute for 2 mm ID columns or 2.0 ml/minute for 4 mm ID columns. The SFC FID signal was integrated into paraffin and naphthenic regions. In addition to characterizing aromatics according to ASTM D5186, a supercritical fluid chromatograph was used to analyze samples for split of total paraffins and total naphthenes. A variety of standards employing typical molecular types can be used to calibrate the paraffin/naphthene split for quantification.

In this discussion, the term “paraffin” refers to a saturated hydrocarbon chain. Thus, a paraffin is an alkane that does not include a ring structure. The paraffin may be straight-chain or branched-chain and is considered to be a non-ring compound. “Paraffin” is intended to embrace all structural isomeric forms of paraffins.

In this discussion, the term “naphthene” refers to a cycloalkane (also known as a cycloparaffin). Therefore, naphthenes correspond to saturated ring structures. The term naphthene encompasses single-ring naphthenes and multi-ring naphthenes. The multi-ring naphthenes may have two or more rings, e.g., two-rings, three-rings, four-rings, rive-rings, six-rings, seven-rings, eight-rings, nine-rings, and ten-rings. The rings may be fused and/or bridged. The naphthene can also include various side chains, such as one or more alkyl side chains of 1-10 carbons.

In this discussion, the term “saturates” refers to all straight chain, branched, and cyclic paraffins. Thus, saturates correspond to a combination of paraffins and naphthenes. In this discussion, the term “cyclic hydrocarbons” refers to a combination of aromatics and naphthenes.

In this discussion, the term “aromatic ring” means five or six atoms joined in a ring structure wherein (i) at least four of the atoms joined in the ring structure are carbon atoms and (ii) all of the carbon atoms joined in the ring structure are aromatic carbon atoms. Therefore, aromatic rings correspond to unsaturated ring structures. Aromatic carbons can be identified using, for example, ¹³C Nuclear Magnetic Resonance. Aromatic rings having atoms attached to the ring (e.g., one or more heteroatoms, one or more carbon atoms, etc.) but which are not part of the ring structure are within the scope of the term “aromatic ring.” Additionally, it is noted that ring structures that include one or more heteroatoms (such as sulfur, nitrogen, or oxygen) can correspond to an “aromatic ring” if the ring structure otherwise falls within the definition of an “aromatic ring”.

In this discussion, the term “non-aromatic ring” means four or more carbon atoms joined in at least one ring structure wherein at least one of the four or more carbon atoms in the ring structure is not an aromatic carbon atom. Non-aromatic rings having atoms attached to the ring (e.g., one or more heteroatoms, one or more carbon atoms, etc.), but which are not part of the ring structure, are within the scope of the term “non-aromatic ring.”

In this discussion, the term “aromatics” refers to all compounds that include at least one aromatic ring. Such compounds that include at least one aromatic ring include compounds that have one or more hydrocarbon substituents. It is noted that a compound including at least one aromatic ring and at least one non-aromatic ring falls within the definition of the term “aromatics”.

It is noted that that some hydrocarbons present within a feed or product may fall outside of the definitions for paraffins, naphthenes, and aromatics. For example, any alkenes that are not part of an aromatic compound would fall outside of the above definitions. Similarly, non-aromatic compounds that include a heteroatom, such as sulfur, oxygen, or nitrogen, are not included in the definition of paraffins or naphthenes.

Categories of Fuels

A fuel is a gaseous, liquid, or solid material used as an energy source for combustion devices, including but not limited to combustion engines in land-based, aeronautical, or marine vehicles, combustion engines in generators, furnaces, boilers, and other combustion devices that are used to provide heat or power. A fuel composition is understood to refer to a gaseous, liquid, or solid material that can be used as a fuel. For certain combustion devices, proper combustion or operation of the combustion device may be ensured by controlling fuel properties. The necessary properties of a fuel for specific combustion devices may be specified in standard specification documents. In order to be suitable for its end use application in a combustion engine or other combustion device, a gaseous, liquid, or solid fuel composition or material may require the addition of one or more fuel additives. Fuels may be derived from renewable or conventional sources, or a combination of both. A blend of one or more fatty acid alkyl esters with a resid-containing fraction can be referred to as a fuel composition.

A fuel blending component, also referred to herein as “component” or a fuel “fraction,” which may be used interchangeably in the specification and the claims, refers to a liquid constituent that is blended with other fuel blending components, other components, or fuel fractions into the overall fuel composition. In some cases, fuel blending components may possess the appropriate properties for use in a combustion device without further modification. Fuel blending components may be combined (blended) with fuels, other fuel blending components, or fuel additives to form a finished fuel or fuel composition that possesses the appropriate properties for use in a combustion device. Fuel blending components may be derived from renewable or conventional sources.

A conventional fuel is a fuel or fuel composition derived from one or more conventional fuel blending components. Conventional fuel blending components are derived from conventional hydrocarbon sources such as crude oil, natural gas, liquid condensates, heavy oil, shale oil, and oil sands, as described in ASTM D4175.

A renewable fuel is a fuel or fuel composition derived from one or more renewable blending components. Renewable blending components are derived from naturally-replenishing energy sources, such as biomass, water, and electricity produced from hydropower, wind, solar, or geothermal sources. Biofuels are a subset of renewable fuels manufactured from biomass-derived feedstocks (e.g. plant or animal based materials). Examples of biofuels include, but are not limited to, fatty acid methyl esters (FAME) and hydrotreated vegetable oils (HVO). The distillate boiling range fraction of a hydrotreated vegetable oil (HVO) is also referred to as renewable diesel.

A hydrocarbon is a compound composed only of hydrogen and carbon atoms. As described in ASTM D4175, hydrocarbon fuels consist primarily of hydrocarbon compounds, but may also contain impurities and contaminants from the fuel's raw materials and manufacturing processes.

Life Cycle Assessment and Carbon Intensity

Life cycle assessment (LCA) is a method of quantifying the “comprehensive” environmental impacts of manufactured products, including fuel products, from “cradle to grave”. Environmental impacts may include greenhouse gas (GHG) emissions, freshwater impacts, or other impacts on the environment associated with the finished product. The general guidelines for LCA are specified in ISO 14040.

The “carbon intensity” of a fuel product (e.g. marine fuel oil or marine gas oil) is defined as the life cycle GHG emissions associated with that product (g CO₂eq) relative to the energy content of that fuel product (MJ, U-V basis). Life cycle GHG emissions associated with fuel products must include GHG emissions associated with crude oil production; crude oil transportation to a refinery; refining of the crude oil; transportation of the refined product to point of “fill”; and combustion of the fuel product.

GHG emissions associated with the stages of refined product life cycles are assessed as follows.

(1) GHG emissions associated with drilling and well completion—including hydraulic fracturing, shall be normalized with respect to the expected ultimate recovery of sales-quality crude oil from the well.

(2) All GHG emissions associated with the production of oil and associated gas, including those associated with (a) operation of artificial lift devices, (b) separation of oil, gas, and water, (c) crude oil stabilization and/or upgrading, among other GHG emissions sources shall be normalized with respect to the volume of oil transferred to sales (e.g. to crude oil pipelines or rail). The fractions of GHG emissions associated with production equipment to be allocated to crude oil, natural gas, and other hydrocarbon products (e.g. natural gas liquids) shall be specified accordance with ISO 14040.

(3) GHG emissions associated with rail, pipeline or other forms of transportation between the production site(s) to the refinery shall be normalized with respect to the volume of crude oil transferred to the refinery.

(4) GHG emissions associated with the refining of crude oil to make liquefied petroleum gas, gasoline, distillate fuels and other products shall be assessed, explicitly accounting for the material flows within the refinery. These emissions shall be normalized with respect to the volume of crude oil refined.

(5) All of the preceding GHG emissions shall be summed to obtain the “Well to refinery” (WTR) GHG intensity of crude oil (e.g. kg CO₂eq/bbl crude).

(6) For each refined product, the WTR GHG emissions shall be divided by the product yield (barrels of refined product/barrels of crude), and then multiplied by the share of refinery GHG specific to that refined product. The allocation procedure shall be conducted in accordance with ISO 14040. This procedure yields the WTR GHG intensity of each refined product (e.g. kg CO₂eq/bbl gasoline).

(7) GHG emissions associated with rail, pipeline or other forms of transportation between the refinery and point of fueling shall be normalized with respect to the volume of each refined product sold. The sum of the GHG emissions associated with this step and the previous step of this procedure is denoted the “Well to tank” (WTT) GHG intensity of the refined product.

(8) GHG emissions associated with the combustion of refined products shall be assessed and normalized with respect to the volume of each refined product sold.

(9) The “carbon intensity” of each refined product is the sum of the combustion emissions (kg CO₂eq/bbl) and the “WTT” emissions (kg CO₂eq/bbl) relative to the energy value of the refined product during combustion. Following the convention of the EPA Renewable Fuel Standard 2, these emissions are expressed in terms of the low heating value (LHV) of the fuel, i.e. g CO₂eq/MJ refined product (LHV basis).

For a conventionally produced marine residual fuel, a carbon intensity of 95.8 g CO₂eq/MJ refined product or more would be expected based on life cycle analysis. This baseline value comes from Department of Energy, Argonne National Laboratory GREET 2020 model for 0.1 wt % sulfur heavy fuel oil. By reducing or minimizing refinery processing, such as by avoiding hydroprocessing, the carbon intensity for a fuel can be reduced by 1% to 10% relative to a conventional fuel. This can result in, for example, a marine residual fuel with a carbon intensity of 94.8 g CO₂eq/MJ refined product or less, or 93.9 g CO₂eq/MJ refined product or less, or 91.0 g CO₂eq/MJ refined product or less, such as down to 86.2 g CO₂eq/MJ refined product or possibly still lower.

As an example of the benefits of using lower carbon intensity methods for extraction, if crude oil is produced with an upstream GHG intensity of 10 kg CO₂eq/bbl, has 3.0 wt % sulfur or less, and an API gravity of 40 or more, then a substantial majority of the time, a resid fraction refined from such a crude oil can have a “well to wheel” GHG intensity that is 10% lower than the conventional value of 95.8 g CO₂eq/MJ refined product or more.

As another example, if crude oil is produced with an upstream GHG intensity of 10 kg CO₂eq/bbl, has 3.0 wt % sulfur or less, and an API gravity of 30 or more, then a majority of the time, a resid fraction refined from such a crude oil can have a “well to wheel” GHG intensity (otherwise known as “carbon intensity”) that is 10% lower than the conventional value of 95.8 g CO₂eq/MJ refined product or more.

As still another example, if crude oil is produced with an upstream GHG intensity of 30 kg CO₂eq/bbl, has 3.0 wt % sulfur or less, and an API gravity of 40 or more, then in some instances, a resid fraction refined from such a crude oil can have a “well to wheel” GHG intensity (otherwise known as “carbon intensity”) that is 10% lower than the conventional value of 95.8 g CO₂eq/MJ refined product or more.

As yet another example, if crude oil is produced with an upstream GHG intensity of 20 kg CO₂eq/bbl, has 3.0 wt % sulfur or less, and an API gravity of 40 or more, then a substantial majority of the time, a resid fraction refined from such a crude oil can have a “well to wheel” GHG intensity (otherwise known as “carbon intensity”) that is 10% lower than the conventional value of 95.8 g CO₂eq/MJ refined product or more.

In this discussion, a low carbon intensity fuel or fuel blending product corresponds to a fuel or fuel blending product that has reduced GHG emissions per unit of lower of heating to value relative to a fuel or fuel blending product derived from a conventional petroleum source. In some aspects, the reduced GHG emissions can be due in part to reduced refinery processing. For example, fractions that are not hydroprocessed for sulfur removal have reduced well-to-refinery emissions relative to fractions that require hydroprocessing prior to incorporation into a fuel. In various aspects, an unexpectedly high weight ratio of naphthenes to aromatics in a shale oil fraction can indicate a fraction with reduced GHG emissions, and therefore a lower carbon intensity.

Another indicator of a low carbon intensity fuel can be an elevated ratio of aliphatic sulfur to total sulfur in a fuel or fuel blending product. Aliphatic sulfur is generally easier to remove than other types of sulfur present in a hydrocarbon fraction. In a hydrotreated fraction, the aliphatic sulfur will typically be removed almost entirely, while other types of sulfur species will remain. The presence of increased aliphatic sulfur in a product can indicate a lack of hydroprocessing for the product. For example, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more (or 0.3 or more, such as up to 0.8 or possibly still higher) can indicate a product that has not been exposed to hydroprocessing conditions, while a weight ratio of aliphatic sulfur to total sulfur of less than 0.1 can indicate a product that has been hydroprocessed.

Still another indicator of a low carbon intensity fuel can be an elevated ratio of basic nitrogen to total nitrogen in a fuel or fuel blending product. Basic nitrogen is typically easier to remove by hydrotreatment. The presence of an increased amount of basic nitrogen in a product can therefore indicate a lack of hydroprocessing for the product. For example, a weight ratio of basic nitrogen to total nitrogen of 0.2 or more (or 0.3 or more, such as up to 0.8 or possibly still higher) can indicate a product that has not been exposed to hydroprocessing conditions, while a weight ratio of basic nitrogen to total nitrogen of less than 0.2, or less than 0.1, can indicate a product that has been hydroprocessed.

Yet another indicator of a low carbon intensity fuel or fuel blending product can be an elevated content of sodium and/or calcium in the product. Hydrotreating processes are generally effective for removal of metals during hydroprocessing, including removal of sodium and calcium. For a hydrotreated product, a typical sodium level is roughly 1 wppm or less, while a typical calcium level is roughly 1-7 wppm. By contrast, for resid fractions derived from shale crude oils with high naphthene to aromatic ratios, the sodium level without hydrotreatment is greater than 5 wppm. For example, the sodium content without hydrotreatment can be 5 wppm to 25 wppm, or 8 wppm to 25 wppm. Similarly, the calcium level without hydrotreatment can be greater than 10 wppm, such as 10 wppm to 25 wppm. The presence of such elevated levels of sodium and/or calcium in a product can indicate a lack of hydroprocessing.

Yet other ways of reducing carbon intensity for a hydrocarbon fraction can be related to methods used for extraction of a crude oil. For example, carbon intensity for a fraction can be reduced by using solar power, hydroelectric power, or another renewable energy source as the power source for equipment involved in the extraction process, either during drilling and well completion and/or during production of crude oil. As another example, extracting crude oil from an extraction site without using artificial lift can reduce the carbon intensity associated with a fuel.

Characterization of Shale Crude Oils and Shale Oil Fractions—General

Shale crude oils were obtained from a plurality of different shale oil extraction sources. Assays were performed on the shale crude oils to determine various compositional characteristics and properties for the shale crude oils. The shale crude oils were also fractionated to form various types of fractions, including fractionation into atmospheric resid fractions, vacuum resid fractions, distillate fractions (including kerosene, diesel, and vacuum gas oil boiling range fractions), and naphtha fractions. Various types of characterization and/or assays were also performed on these additional fractions.

The characterization of the shale crude oils and/or crude oil fractions included a variety of procedures that were used to generate data. For example, data for boiling ranges and fractional distillation points was generated using methods similar to compositional or pseudo compositional analysis such as ASTM D2887. For compositional features, such as the amounts of paraffins, isoparaffins, olefins, naphthenes, and/or aromatics in a crude oil and/or crude oil fraction, data was generated using analytical techniques such as high pressure liquid chromatography (HPLC) and/or gas chromatography—mass spectrometry (GC-MS). Data related to pour point was generated using methods similar to ASTM D97. Data related to cloud point was generated using methods similar to ASTM D2500 and/or ASTM D5773. Data related to flash point was generated based on volatility calculations. Data related to sulfur content and nitrogen content of a crude oil and/or crude oil fraction was generated using methods similar to ASTMD2622, ASTM D4294, ASTM D5443, ASTM D4629, and/or ASTM D5762. Data related to carbon content and/or hydrogen content was calculated based on the compositional analysis. Data related to density (such as density at 15° C.) was generated using methods similar to ASTM D1298 and/or ASTM D4052. Data related to kinematic viscosity (such as kinematic viscosity at 40° C. or 50° C.) was generated using methods similar to ASTM D445 and/or ASTM D7042. Data related to micro carbon residue (MCR) content was generated using methods similar to ASTM D189 and/or ASTM D4530. Data related to cetane index was calculated from fractional distillation using techniques similar to those represented in the American Petroleum Institute Technical Data Book. Data related to acid number was generated using methods similar to ASTM D664, ASTM D3242, and ASTM D8045.

The data and other measured values for the shale crude oils and shale oil fractions were then incorporated into an existing data library of other representative conventional and non-conventional crude oils for use in an empirical model. The empirical model was used to provide predictions for compositional characteristics and properties for some additional shale oil fractions that were not directly characterized experimentally. In this discussion, data values provided by this empirical model will be described as modeled data. In this discussion, data values that are not otherwise labeled as modeled data correspond to measured values and/or values that can be directly derived from measured values. An example of such an empirical model is AVEVA Spiral Suite 2019.3 Assay by AVEVA Solutions Limited.

FIGS. 1 and 2 show examples of the unexpected combinations of properties for shale crude oils that have a high weight ratio and/or volume ratio of naphthenes to aromatics. In FIG. 1, both the weight ratio and the volume ratio of naphthenes to aromatics is shown for 56 shale crude oils relative to the weight/volume percentage of aromatics in the shale crude oil. The top plot in FIG. 1 shows the volume ratio of naphthenes to aromatics, while the bottom plot shows the weight ratio. A plurality of other representative conventional crudes are also shown in FIG. 1 for comparison. As shown in FIG. 1, the selected shale crude oils described herein have an aromatics content of less than 21.2 vol % while also having a volume ratio of naphthenes to aromatics of 1.6 or more. Similarly, as shown in FIG. 1, the selected shale crude oils described herein have an aromatics content of less than 24.7 wt % while also having a weight ratio of naphthenes to aromatics of 1.5 or more. By contrast, none of the conventional crude oils shown in FIG. 1 have a similar combination of aromatics content of less than 21.2 vol % and a volume ratio of naphthenes to aromatics of 1.5 or more, or a combination of aromatics content of less than 24.7 wt % and a weight ratio of naphthenes to aromatics of 1.5 or more. It has been discovered that this unexpected combination of naphthenes to aromatics ratio and aromatics content is present throughout various fractions that can be derived from such selected shale crude oils.

In FIG. 2, both the volume ratio and weight ratio of naphthenes to aromatics is shown for the 56 shale crude oils in FIG. 1 relative to the weight of sulfur in the crude. The top plot in FIG. 2 shows the volume ratio of naphthenes to aromatics, while the bottom plot shows the weight ratio. The plurality of other representative conventional crude oils are also shown for comparison. As shown in FIG. 2, the selected shale crude oils described herein have a sulfur level of less than about 0.1 wt % while also having a volume ratio of naphthenes to aromatics of 1.6 or more. Similarly, as shown in FIG. 2, the selected shale crude oils described herein have a sulfur level of less than about 0.1 wt % while also having a weight ratio of naphthenes to aromatics of 1.5 or more. By contrast, none of the conventional crude oils shown in FIG. 2 have a similar combination of a sulfur level of less than 0.1 wt % while also having a volume ratio of naphthenes to aromatics of 1.6 or more, or a sulfur level of less than 0.1 wt % while also having a weight ratio of naphthenes to aromatics of 1.5 or more. Additionally, the selected shale crude oils have a sulfur content of roughly 0.1 wt % or less, while all of the conventional crude oils shown in FIG. 2 have a sulfur content of greater than 0.2 wt %. It has been discovered that this unexpected combination of high naphthene to aromatics ratio and low sulfur is present within various fractions that can be derived from such selected crude oils. This unexpected combination of properties contributes to the ability to produce low carbon intensity fuels from shale oil fractions and/or blends of shale oil fractions derived from the shale crude oils.

It is noted that due to the difference in density between naphthenes and aromatics, the naphthenes to aromatics volume ratios shown in FIGS. 1 and 2 are roughly 10%-12% greater than the naphthenes to aromatics weight ratios in FIGS. 1 and 2. It is believed that this difference is also present for the various other fractions described herein.

Characterization of Shale Oil Fractions—Atmospheric Resids and Corresponding Fuel Oils

In some aspects, an atmospheric resid fraction of a shale oil as described herein or a fraction including both distillate and atmospheric resid can be used as a marine fuel oil or as a blending component for a marine fuel oil. The combination of low sulfur, high naphthene to aromatics ratio, low density, and low kinematic viscosity can allow an atmospheric resid fraction to be used as a marine fuel oil with reduced or minimized processing, such as possibly using the fraction as a fuel oil after distillation without further processing.

FIG. 3 shows modeled values (from the empirical model described above) for selected high naphthene to aromatic ratio atmospheric resid fractions for 5 different shale crude oils and/or shale crude oil blends. The atmospheric resid fractions in FIG. 3 are based on 5 out of the 56 shale crude oils and/or shale crude oil blends shown in FIGS. 1 and 2. For comparison, FIG. 3 shows modeled values for an atmospheric resid fraction from a light sweet crude oil, as well as measured values for one conventional very low sulfur fuel oil (VLSFO). The modeled atmospheric resid fractions have an initial boiling point of 371° C. and a final boiling point (FBP) between approximately 1050 to 1200° C. The aromatic content of the VLSFO was determined by a method specified in the Explanatory Notes to the Combined Nomenclature list of the European Union, Annex A.

FIG. 4 shows modeled values (from the empirical model described above) for selected high naphthene to aromatic ratio atmospheric resid fractions for 56 different shale crude oils and/or shale crude oil blends. The atmospheric resid fractions in FIG. 4 are based on the 56 shale crude oils and/or shale crude oil blends shown in FIGS. 1 and 2. For comparison, FIG. 4 shows modeled values for atmospheric resid fractions from ten conventional crude oils, as well as measured values for one conventional very low sulfur fuel oil (VLSFO). Also for comparison, FIG. 4 includes selected specification limits from a marine fuel specification (ISO 8217 RME180, VLSFO Sulfur Level). The modeled atmospheric resid fractions have an initial boiling point of 371° C. and a final boiling point between approximately 1050 to 1200° C. The aromatic content of the VLSFO was determined by a method specified in the Explanatory Notes to the Combined Nomenclature list of the European Union, Annex A.

As shown in FIG. 4, all of the modeled high naphthene to aromatics ratio, low sulfur atmospheric resid fractions derived from shale crude oil sources have a lower sulfur content than the conventional atmospheric resid fraction. The sulfur content for the shale atmospheric resid fractions is less than 0.25 wt %, or less than 0.1 wt %, or less than 0.07 wt %, or less than 0.05 wt %, such as down to 0.005 wt %. Additionally, because the modeled atmospheric resid fractions have not been hydroprocessed, the weight ratio of aliphatic sulfur to total sulfur ranges from 0.32 to 1.00. Thus, the modeled atmospheric resid fractions have a weight ratio of aliphatic sulfur to total sulfur of greater than 0.2, or greater than 0.3. This is in contrast to a hydroprocessed fraction, which would be expected to have a weight ratio of aliphatic sulfur to total sulfur of 0.1 or less.

The modeled high naphthene to aromatics ratio, low sulfur atmospheric resid fractions derived from shale crude oil sources also have a lower nitrogen content than the conventional atmospheric resid fraction. The nitrogen content for the shale atmospheric resid fractions is less than 2100 wppm, or less than 1000 wppm, or less than 800 wppm, or less than 600 wppm, such as down to 25 wppm or possibly still lower. Additionally, because the modeled atmospheric resid fractions have not been hydroprocessed, the weight ratio of basic nitrogen to total nitrogen ranges from 0.2 to 1.0 for most of the atmospheric tower resid fractions (of the 56 atmospheric tower resid fractions, three have a basic nitrogen to total nitrogen ratio between 0.07 to 0.15). Thus, the modeled atmospheric resid fractions optionally have a weight ratio of basic nitrogen to total nitrogen of greater than 0.2, or greater than 0.3, in conjunction with a weight ratio of aliphatic sulfur to total sulfur of greater than 0.2. This is in contrast to a hydroprocessed fraction, which would be expected to have a weight ratio of basic nitrogen to total nitrogen less than 0.2, or less than 0.1, in conjunction with a weight ratio of aliphatic sulfur to total sulfur of 0.1 or less.

The modeled high naphthene to aromatics ratio, low sulfur atmospheric resid fractions also have a lower kinematic viscosity at 50° C., and a lower density at 15° C. than the conventional atmospheric resid fraction. The density for the shale atmospheric resid fractions is less than 915 kg/m³ for the shale atmospheric resid fractions, or less than 900 kg/m³, or less than 890 kg/m³, such as down to 855 kg/m³. The kinematic viscosity at 50° C. is less than 250 cSt for the shale atmospheric resid fractions, or less than 180 cSt, or less than 160 cSt, or less than 150 cSt, or less than 130 cSt, or less than 120 cSt, or less than 110 cSt, such as down to 20 cSt. In some aspects, the kinematic viscosity at 50° C. is about 20 cSt to 250 cSt, or between 40 cSt to 150 cSt, or between 40 cSt to 120 cSt. Additionally, all of the shale atmospheric resid fractions have a volume ratio of naphthenes to aromatics of 0.8 or more, or 1.5 or more, or 2.0 or more, or 2.5 or more, such as up to 6.0 or possibly still higher. In terms of weight ratio of naphthenes to aromatics, all of the shale atmospheric resid fractions have a weight ratio of naphthenes to aromatics of 0.75 or more, or 1.3 or more, or 1.5 or more, or 1.8 or more, or 2.0 or more, or 2.5 or more, such as up to 6.0 or possibly still higher.

It is noted in FIG. 3 that the kinematic viscosity at 50° C. of the atmospheric resid from the conventional light sweet crude oil is greater than 180 cSt. As a result, the conventional atmospheric resid does not meet the specifications for an RME 180 fuel oil without some type of modification, such as blending with a distillate flux. Additionally, it is noted that the sulfur content of the atmospheric resid from the conventional light sweet crude oil is greater than 0.5 wt %. This means that some type of hydroprocessing or other sulfur treatment (or possibly blending with a sufficient amount of low sulfur distillate) would be needed for the atmospheric resid from the light sweet crude to be used as a fuel oil (such as RME180).

Since blending and hydroprocessing would be needed anyway, fuel oils are not conventionally made from atmospheric resid fractions. Instead, a further distillation is usually performed to form a vacuum resid fraction. This potentially allows additional value to be captured for the 370° C.-565° C. portion of the atmospheric resid by allowing this lower boiling fraction to be incorporated into higher value products. A vacuum resid fraction, however, typically has a kinematic viscosity at 50° C. that is substantially higher than the specification for use as a fuel oil. In order to meet fuel oil specifications, a distillate is typically blended with the vacuum resid fraction to correct the kinematic viscosity to a desired level. The addition of distillate typically reduces the flash point of the resulting blend to just above the minimum flash point for a fuel oil of roughly 60° C. By contrast, the shale oil atmospheric resid fractions shown in FIG. 3 have a sufficiently low kinematic viscosity to be used without addition of a distillate flux. As a result, a fuel oil formed based on a shale oil atmospheric resid fraction can have a flash point of 100° C. or more, or 120° C. or more, or 150° C. or more, or 200° C. or more, such as up to 250° C. or possibly still higher.

The shale oil atmospheric resid fractions in FIG. 4 have still other potentially beneficial features. These features can include a naphthenes content of 30 vol % to 60 vol %, or 35 vol % to 60 vol %, or 40 vol % to 60 vol %, or 45 vol % to 60 vol %; or expressed as wt %, a naphthenes content of 30 wt % to 55 wt %, or 35 wt % to 55 wt %, or 40 wt % to 55 wt %, or 45 wt % to 55 wt %. Another feature can be an aromatics content of 45 wt %/45 vol % or less, or 35 wt %/35 vol % or less, or 30 wt %/30 vol % or less, or 25 wt %/25 vol % or less, such as down to 10 wt %/10 vol % or possibly lower. Yet another feature can be an unexpectedly low micro carbon residue for a resid fraction, such as a micro carbon residue of 3.0 or less, or 2.5 wt % or less, or 1.0 wt % or less, such as down to 0.05 wt % or possibly still lower. Still other features can include a hydrogen content of 11.0 wt % or more; a nitrogen content of 2100 wppm or less, or 1000 wppm or less; a BMCI of 18 to 40, or 18 to 35; an n-heptane insolubles content of 0.01 wt % to 1.5 wt %, or 0.01 wt % to 1.0 wt %, or 0.01 wt % to 0.5 wt %, or 0.01 wt % to 0.1 wt %; and a CCAI of 795 or less, or 790 or less, or 770 or less, such as down to 740 or possibly still lower.

For a fuel oil made from a shale oil atmospheric resid fraction as shown in FIG. 4, still other characteristics of the fuel oil can be related to compositional differences that can be found in fractions that are not exposed to hydrotreating conditions. As noted above, aliphatic sulfur is typically easily removed from a petroleum fraction, while other types of sulfur are removed more slowly. In some aspects, since hydrotreating is not necessary to reduce the sulfur level, a fuel oil made from an atmospheric resid fraction with a high naphthene to aromatics ratio can have an elevated ratio of aliphatic sulfur to total sulfur in the fuel oil. Similarly, the amount of basic nitrogen (more easily removed under hydroprocessing conditions) can be high relative to the amount of total nitrogen. Additionally, by avoiding the need for hydroprocessing, the amount of sodium and/or calcium in the fuel oil can be higher than a conventional low sulfur or very low sulfur fuel oil.

It is noted that while all of the 56 modeled shale fractions shown in FIG. 4 included a set of common features including a T90 of 500° C. or more, a kinematic viscosity at 50° C. between 20 cSt to 250 cSt, a BMCI of 40 or less, a sulfur level of 0.33 wt % or less, and a ratio of aliphatic to total sulfur of 0.2 or more, other shale fractions have been discovered that include less than all of these features. FIG. 4 shows a comparison of 11 additional modeled shale fractions that differ from the 56 modeled shale atmospheric resid fractions in FIG. 4 based on one or more of T90, kinematic viscosity at 50° C., BMCI, sulfur, and/or ratio of aliphatic to total sulfur. The 11 additional modeled shale fractions are shown in the middle column of FIG. 4. For the 11 additional modeled shale fractions, each of the fractions have at least one of the following properties: a T90 less than 500° C., a BMCI greater than 40, a sulfur content greater than 0.33 wt %, or a combination thereof.

As shown in FIG. 4, the 11 modeled additional shale fractions that have been discovered can have some properties that overlap with the 56 modeled atmospheric resid shale fractions from FIG. 4. However, it can also be seen that because the 11 modeled additional shale fractions do not have the combination of a T90 greater than 500° C., a BMCI less than 40, or a sulfur content less than 0.33 wt %, the resulting average properties for the 11 modeled additional shale fractions can generally differ from the 56 modeled shale atmospheric resid fractions. For example, most of the 11 modeled additional shale fractions have a BMCI near the upper limit or above the upper limit of 40, resulting in an average BMCI of 37 among the 11 additional modeled fractions, compared to an average BMCI of 30 among the 56 modeled shale atmospheric resid fractions. Additionally, the 11 modeled additional shale fractions have sulfur values toward the higher end or above the upper limit (0.043 wt % to 0.873 wt %), and low naphthene to aromatics weight ratios (0.58-0.96) compared to the 56 modeled shale atmospheric resid fractions.

FIGS. 5 and 6 show modeled compositional values and properties for an alternative type of resid fraction that includes both distillate and atmospheric resid (referred to herein as “alternative resid fraction”). The modeled fractions in FIGS. 5 and 6 could be formed, for example, by distilling off the naphtha (and lighter) portions of a shale crude oil. This can allow for still lower carbon intensity when producing a fuel oil, such as an RMA 10 very low sulfur fuel oil according to Table 1 of ISO 8217. The modeled fractions in FIGS. 5 and 6 have an initial boiling point of roughly 145° C., a T10 distillation point between 177° C. to 221° C., and a T90 distillation point between 401° C. and 496° C.

FIG. 5 shows modeled values (from the empirical model described above) for selected high naphthene to aromatic ratio alternative resid fractions for 5 different shale crude oils and/or shale crude oil blends. For comparison, FIG. 5 shows modeled values for an alternative resid fraction from a light sweet crude oil, as well as measured values for one conventional very low sulfur fuel oil (VLSFO). Also for comparison purposes, FIG. 5 includes a selection of limits from the marine fuel specification ISO 8217 RMA10.

FIG. 6 shows modeled values (from the empirical model described above) for selected high naphthene to aromatic ratio alternative resid fractions for 57 different shale crude oils and/or shale crude oil blends. As shown in FIG. 6, all of the high naphthene to aromatics ratio, low sulfur fuel oils derived from shale crude oil sources have a lower sulfur content than the conventional distillate plus atmospheric resid fraction. The sulfur content for the shale alternative atmospheric resid fractions is less than 0.33 wt %, for example less than 0.30 wt %, or 0.25 wt %, or 0.20 wt %, or 0.15 wt %, or 0.10 wt %, and down to 0.006 wt %. Additionally, because the modeled atmospheric resid fractions have not been hydroprocessed, the weight ratio of aliphatic sulfur to total sulfur ranges from 0.31 to 1.00. Thus, the modeled atmospheric resid fractions have a weight ratio of aliphatic sulfur to total sulfur of greater than 0.5, or greater than 0.6. This is in contrast to a hydroprocessed fraction, which would be expected to have a weight ratio of aliphatic sulfur to total sulfur of 0.1 or less.

As shown in FIG. 6, all of the high naphthene to aromatics ratio, low sulfur fuel oils derived from shale crude oil sources have a lower nitrogen content than the conventional distillate plus atmospheric resid fraction. The nitrogen content for the shale alternative atmospheric resid fractions is less than 950 wppm, and is less than 500 wppm for 45 of the 57 fractions, such as down to 15 wppm. Additionally, because the modeled alternative atmospheric resid fractions have not been hydroprocessed, the weight ratio of basic nitrogen to total nitrogen ranges from 0.08 to 0.59. Thus, the modeled alternative atmospheric resid fractions have a weight ratio of basic nitrogen to total nitrogen of greater than 0.1, and greater than 0.2 for 53 of the 57 fractions. This is in contrast to a hydroprocessed fraction, which would be expected to have a weight ratio of basic nitrogen to total nitrogen less than 0.05, or less than 0.01.

As shown in FIG. 6, all of the high naphthene to aromatics ratio, low sulfur fuel oils derived from shale crude oil sources also have a lower kinematic viscosity at 50° C. and a lower density at 15° C. than the conventional atmospheric resid fraction. The sulfur content for the shale atmospheric resid fractions is less than 0.33 wt %, for example less than 0.30 wt %, or 0.25 wt %, or 0.20 wt %, or 0.15 wt %, or 0.10 wt %, and such as down to 0.006 wt %. The density for the shale atmospheric resid fractions is less than 870 kg/m³ for the shale atmospheric resid fractions, and is less than 860 kg/m³ for 51 of the 57 fractions, or less than 845 kg/m³, such as down to 810 kg/i. The kinematic viscosity at 50° C. is less than 8.0 cSt for the shale atmospheric resid fractions, and is less than 7.0 cSt for 55 of the 57 fractions, or less than 5.0 cSt, such as down to 2.5 cSt.

Additionally, all of the shale distillate plus atmospheric resid fractions have a weight ratio and volume ratio of naphthenes to aromatics of greater than 1.3, and 50 of the 57 fractions have a weight ratio and volume ratio of naphthenes to aromatics of greater than 1.5, or greater than 2.0, or greater than 3.0, such as up to 6.0 or possibly still higher. Relative to the atmospheric resids shown in FIG. 4, the alternative resid fractions in FIG. 6 have higher paraffin contents in exchange for lower aromatic contents.

The shale oil resid fractions in FIG. 6 have still other potentially beneficial features. These features can include a naphthenes content of 30 wt % to 55 wt % or 34 wt % to 55 wt % or 38 wt % to 55 wt %, or 40 wt % to 55 wt %. Another feature can be an aromatics content of 32 wt %/32 vol % or less, or 26 wt %/26 vol % or 20 wt %/20 vol % or less, or 15 wt %/15 vol % or less, such as down to 5.0 wt %/5 vol % or possibly lower. Yet another feature can be an unexpectedly low micro carbon residue for a resid fraction, such as a micro carbon residue of 1.1 wt % or less, or 0.5 wt % or less, such as down to 0.02 wt % or possibly still lower. Still other features can include a nitrogen content of 950 wppm or less, or 850 wppm or less, or 750 wppm or less or 250 wppm or less; a BMCI of 20 to 35, or 20 to 30; an n-heptane insolubles content of 0.5 wt % or less, or 0.3 wt % or less, such as down to 0.1 wt %; and a CCAI of 800 or less, or 790 or less, or 780 or less, such as down to 750 or possibly still lower.

It is noted that while all of the 57 modeled shale fractions shown in FIG. 6 included a set of common features such as a T10 distillation point of 150° C. to 230° C., a T90 distillation point of 400° C. or more, a kinematic viscosity at 50° C. of 2.0 cSt to 8.0 cSt, a sulfur content of 0.33 wt % or less, a density at 15° C. of 870 kg/m³ or less, a BMCI of 35 or less, and a weight ratio of naphthenes to aromatics of 1.3 or more, other shale fractions have been discovered that include less than all of these features. FIG. 6 shows a comparison of 10 additional modeled shale fractions that differ from the 57 modeled shale alternative resid fractions in FIG. 6 based on one or more of T10, T90, kinematic viscosity at 50° C., a sulfur content, a density at 15° C., BMCI, and weight ratio of naphthenes to aromatics. The 10 additional modeled shale fractions are shown in the middle column of FIG. 6. For the 10 additional modeled shale fractions, each of the fractions have at least one of the following properties: a T10 distillation point below 150° C., a T90 distillation point below 400° C. a kinematic viscosity at 50° C. below 2.0 cSt, a sulfur content above 0.33 wt %, a density at 15° C. above 870 kg/m³, a BMCI above 35, a weight ratio of naphthenes to aromatics of less than 1.3, or a combination thereof.

As shown in FIG. 6, the 10 modeled additional shale fractions that have been discovered can have some properties that overlap with the 57 modeled alternative resid shale fractions from FIG. 6. However, it can also be seen that because the 10 modeled additional shale fractions do not have the combination of T10, TX, kinematic viscosity at 50° C., a sulfur content, a density at 15° C., BMCI, and weight ratio of naphthenes to aromatics, the resulting average properties for the 10 modeled additional shale fractions can generally differ from the 57 modeled shale alternative resid fractions. The 10 modeled additional shale fractions can generally be split into two categories. The first category is characterized by T10, T90, and KV50 on the lower end of the range for the 57 modeled shale fractions shown in FIG. 6, or lower than the range. Shale fractions in this first category are additionally characterized by flash point less than 60° C., below the range for the 57 modeled shale fractions shown in FIG. 6. The second category is characterized by density at 15° C., sulfur, and BMCI on the higher end of the range for the 57 modeled shale fractions shown in FIG. 6, or above the range, and weight ratio of naphthenes to aromatics on the lower end of the range for the 57 modeled shale fractions shown in FIG. 6, or below the range. Shale fractions in the second category are additionally characterized by n-heptane insoluble and micro carbon residue on the higher end of the range for the 57 modeled shale fractions shown in FIG. 6, or above the range.

Fuel Oil and Marine Gas Oil Blends Including Shale Oil Atmospheric Resids

In various examples below, a variety of refinery fractions, renewable fractions and finished fuels are used as representative blending components for the formation of fuel blends. The fuel blends are formed by blending one or more low sulfur, high naphthene to aromatic ratio shale oil fractions with one or more of the refinery fractions, renewable fractions, or finished fuels.

As described above, atmospheric resid fractions derived from low sulfur, high naphthene to aromatic shale oils can be used as fuel oils after reduced or minimized amounts of processing. This can have a corresponding effect of reducing or minimizing the carbon intensity of the resulting fuel due to refinery processing. In addition to using the low carbon intensity atmospheric resids as fuel oils, the atmospheric resids can also be blended with other low carbon intensity fractions to form still lower carbon intensity fuels.

As an example, distillates derived from biological sources can have a substantially lower carbon intensity, due in part to the consumption of carbon during the formation of the biomass. By blending a low carbon intensity atmospheric resid with a biodiesel (or other renweable distillate fraction) can result in a fuel or fuel blending component with a reduced or minimized carbon intensity. Blending a shale oil atmospheric resid fraction with biodiesel can also provide unexpected synergistic advantages. For example, shale oil atmospheric resids can tend to have a relatively high pour point, so the biodiesel can also act as a pour point corrector. Biodiesel can also tend to have high solvency for asphaltenes, so blending biodiesel with a shale oil atmospheric resid can improve the ability to combine the resulting blended product with other resid fractions.

Another potential blending route for low carbon intensity atmospheric resids can be to blend an atmospheric resid with a low sulfur distillate blendstock (such as ultra low sulfur diesel) to form marine gas oils and/or very low sulfur fuel oils. It has been discovered that substantially larger amounts of low carbon intensity atmospheric resids can be blended with conventional distillate fuels while still forming a marine gas oil that satisfies the requirements of a DMB and/or DFB marine gas oil according to ISO 8217. In particular, due to the unexpectedly low micro carbon residue of the atmospheric resids, blends of up to 50 vol % atmospheric resid with 50 vol % distillate can be formed while still meeting the requirements of a DMB or DFB marine gas oil. Blends containing up to 55 vol % atmospheric resid with distillate can also be formed while satisfying the specifications for a fuel oil, such as a RMA 10 fuel oil according to ISO 8217. Thus, blends including 1.0 vol % to 50 vol % of atmospheric resid, or 1.0 vol % to 55 vol % atmospheric resid, can be used to form marine gas oils.

The first two columns of Table 1 show two types of biodiesels that were used as blend components for modeling of the formation of fuel oils and marine gas oils. The third column shows a commercial ultra low sulfur diesel that was used for modeling of blending with shale oil atmospheric resid to form fuel oils and marine gas oils.

TABLE 1 Atmospheric Resid Blend Components (Modeled) Biodiesel 1 Biodiesel 2 ULSD Density at 881.1 879.6 830.6 15° C. (kg/m3) KV50 (cSt) 3.5 3.734 2.362 Sulfur (ppm ~5 ~5 0.00039 m/m) CCAI 828 824 BMCI 55 80 26.8 TE 0 0 MCR (wt %) 0 0 0 Cloud Point −1 >1 Pour Point (° C.) <−5 6

Table 2 shows modeling results for blending atmospheric resids from FIG. 3 with varying amounts of biodiesel.

TABLE 2 Low Carbon Intensity Fuel Oil Blends (Modeled) ISO8217 90% FO1 + 10% 95% FO3 + 5% 40% FO3 + 60% 40% FO3 + 60% RMD80 Spec Biodiesel 1 Biodiesel 1 Biodiesel 1 Biodiesel 2 Density at 15° C. <990 0.8684 0.9071 892.1 891.2 (kg/m3) KV50 (cSt) <80 35.3 105 10.1 10.6 Sulfur (wt %) <0.50 126 0.207 0.089 0.089 CCAI <860 760 783 809 807 BMCI — 28 41 49 64 TE — 0 0 0 0 N-Heptane — 0.04 0.07 0.03 0.03 Insolubles (wt %) MCR (wt %) <14 0.05 2.33 1.00 1.00 Pour Point (° C.) <30 ~30 ~29 ~9 ~16

As shown in Table 2, low carbon intensity fuel oils that satisfy the specifications for an RMD80 fuel oil can be formed with blends ranging from 5 vol % to 60 vol % in biodiesel, with the balance (40 vol % to 95 vol %) corresponding to low carbon intensity atmospheric resid. Because of the low sulfur content, density, and kinematic viscosity of the low carbon intensity atmospheric resid fractions, even addition of 5 vol % of biodiesel can result in a blend with satisfactory properties. Additionally, addition of 5 vol % or 10 vol % of biodiesel can be sufficient to form a blended fuel oil product with a pour point of 30 or less. More generally, low carbon fuels can be formed that include 5 wt % to 95 wt % of a shale oil atmospheric resid having a high naphthene to aromatic ratio and a low sulfur content. Also more generally, any convenient type of renewable distillate can be used, such as biodiesel, hydrotreated vegetable oil, or another convenient distillate boiling range fraction derived from a renewable source.

Modeling was also used to combine the atmospheric resids of FIG. 3 with a commercial ultra low sulfur diesel (ULSD) fraction to form potential marine gas oils or fuel oils. Based on the modeling, in contrast to conventional blends of distillates with resid fractions, it was discovered that compatibility and/or sediment formation was not a primary factor in determining whether a blend could form a fuel that satisfied one or more fuel specifications. Instead, it was discovered that the micro carbon residue content was the controlling factor. Due to the low micro carbon residue content of the low carbon intensity atmospheric resid fractions, it was discovered that substantial amounts of atmospheric resid could be added.

FIG. 17 shows modeling results for blending of fuel oils (i.e., modeled atmospheric resids) from FIG. 3 with the ULSD fraction. As shown in FIG. 17, for fuel oil 4, between 30 vol % and 50 vol % of atmospheric resid could be included in the blend while still satisfying the requirements for a DMB or DFB gas oil. Further addition of Fuel Oil 4 (FO4) resulted in a micro carbon residue value outside of the gas oil specification. However, addition of 50 vol % of Fuel Oil 4 still provided a sufficiently low micro carbon residue value to satisfy the specifications for a RMA 10 fuel oil. For Fuel Oil 1, between 50 vol % and 55 vol % of the atmospheric resid could be included in the blend while satisfying the specification for a DMB or DFB gas oil, while 55 vol % of atmospheric resid could be included while satisfying the specifications for a RMA 10 fuel oil. For fuel oil 3, between 10 vol % and 20 vol % of the atmospheric resid could be included in the blend while satisfying the specification for a DMB or DFB gas oil, while 45 vol % of atmospheric resid could be included while satisfying the specifications for a RMA 10 fuel oil.

In contrast to the above results, when blending commercial ULSD with various types of commercial low sulfur fuel oils, addition of even 5 vol % of commercial fuel oil to the blend would result in a micro carbon residue content in excess of the specification for a DMB or DFB gas oil. Additionally, between only 10 vol % and 20 vol % of commercial fuel oil could be added to the commercial ULSD while still meeting the micro carbon residue specification for a RMA 10 fuel oil.

Table 3 shows properties for conventional ultra low sulfur diesels and conventional resid fractions. Table 3 shows properties for the conventional diesel and resid fractions. It is noted that comparative distillate blendstocks A and B correspond to ultra low sulfur diesel fuels, while the comparative resid blendstocks A and B both correspond to commercially available fuel oils.

TABLE 3 Comparative Distillate and Resid Blendstocks Comp. Comp. Comp. Comp. Distillate Resid Distillate Resid Test Blend- Blend- Blend- Blend- Property Method stock A stock A stock B stock B Density at ASTM 0.8286 0.9643 0.8502 976.6 15° C., kg/L D4052 Sulfur, wt % ASTM 0.00054 2.59 0.0003 1.3 D4294 or ASTM D5453 KV50, cSt ASTM — 351.8 2.435 410.5 D445 Sediment, ISO 0 0.01 0 — wt % 10307-2 Asphaltene IP 143 0 5.3 0 2.6 Content, wt % Micro Carbon ASTM 0 15.5 0 12.6 Residue, % D4530 mass

Table 4 shows blend compositions produced by blending various amounts of Comparative Distillate Blendstock A and Comparative Resid Blendstock A. As shown in Table 4, addition of 2 vol % of the resid blendstock results in a micro carbon residue content that is too high to satisfy the DMB specification. Addition of 5 vol % of resid blendstock results in a micro carbon residue content that is too high to satisfy the RMA10 specification.

TABLE 4 Blends Based on Distillate Blendstock A and Resid Blendstock A Blend # 1 2 3 4 5 Distillate Blendstock 2, vol % 99 98 95 90 80 Resid Blendstock 2, vol % ISO ISO 1 2 5 10 20 8217 8217 Property Method Result Result Result Result Result DMB/DFB RMA10 Sediment, % 10307-2* 0.01 0.01 0.01 0.01 0.01 Max Max mass 0.1 0.1 MCR, % mass ASTM D4530 0.2^(†) 0.4^(†) 0.9^(†) 1.8^(†) 3.5^(†) 0.30 2.50

As another comparative example, Comparative Distillate Blendstock B and Comparative Resid Blendstock B were blended in a volume ratio of 70 vol % distillate to 30 vol % to resid. This resulted in a blended composition that contained 3.6 wt % of micro carbon residue, which is well above the specification for either a DMB or an RMA10 fuel. This blend also resulted in a sediment mass of 0.2 wt %, which is greater than the fuel specification value.

Characterization of Shale Oil Fractions—Distillate Fractions and Corresponding Marine Gas Oils

In some aspects, a distillate fraction of a shale oil as described herein can be used as a marine gas oil or as a blending component for amarine gas oil. The combination of low sulfur, high naphthene to aromatics ratio, low density, and low kinematic viscosity can allow a distillate fraction to be used as a marine gas oil with reduced or minimized processing, such as possibly using the fraction as a marine gas oil after distillation without further processing.

FIG. 7 shows measured data for distillate boiling range fractions derived from seven different shale oil and/or shale oil blends. The distillate cuts shown in FIG. 7 are narrow distillate cuts, with a T10 distillation point of roughly 290° C.-300° C. and a T90 distillation point of roughly 350° C. to 360° C. This corresponds roughly to a heavy diesel fraction after removing a jet fuel or kerosene portion. As shown in FIG. 7, these distillate fractions derived from shale crude oils and/or blends of shale crude oils had a relatively low density at 15° C. of 830 kg/m³ to 860 kg/m³, which indicates the presence of an unexpectedly high ratio of naphthenes to aromatics in the distillate fractions. The distillate fractions also had other unexpected combinations of properties, including an unexpectedly high derived cetane number of 60-72, or 62-72; a sulfur content of less than 0.1 wt %, or less than 0.05 wt %, or less than 0.025 wt %; and a nitrogen content of less than 200 wppm, or less than 100 wppm.

FIG. 8 shows modeled data for distillate boiling range fractions (including a portion of kerosene boiling range compounds) derived from the first five shale crude oils shown in FIG. 7. The modeled distillate fractions shown in FIG. 8 have an initial boiling point of 148° C. and a final boiling point of 432° C. This results in a modeled T10 distillation point of 185° C. to 195° C. and a T90 distillation point of 365° C. to 385° C. More generally, the T10 distillation point can be between 150° C. and 230° C. As shown in the modeled compositional values and properties in FIG. 8, the distillate fractions have an unexpectedly high weight ratio and/or volume ratio of naphthenes (cycloparaffins) to aromatics of 2.5 or more, or 3.0 or more, such as up to 8.0 or possibly still higher, while also including 5.0 wt % to 18 wt % aromatics, or 5.0 wt % to 15 wt %, or 5.0 wt % to 12 wt % (or 5.0 vol % to 18 vol %, or 5.0 vol % to 15 vol %, or 5.0 vol % to 12 vol %). The distillate fractions further have an unexpected combination of a low density at 15° C. of 810 kg/m³ to 835 kg/m³ (or 810 kg/m³ to 830 kg/m³); an energy content of 42.9 MJ/kg or greater; a low kinematic viscosity at 40° C. of 2.5 cSt to 2.8 cSt; a low sulfur content of 0.004 wt % to 0.01 wt %, or 0.005 wt % to 0.009 wt %; a low nitrogen content of 150 wppm or less, or 100 wppm or less, or 50 wppm or less, such as down to 1.0 wppm; and an acid number of less than 0.1 mg KOH/kg, or less than 0.08 mg KOH/kg. More generally, the kinematic viscosity at 40° C. can be 2.0 cSt to 4.0 cSt, or 2.5 cSt to 3.2 cSt. The distillate boiling range fractions can also have a cetane index of 45 or more, or 49 or more, such as up to 65 or possibly still higher. Based on the sulfur content, density, and kinematic viscosity, the distillate boiling range fractions in FIG. 8 can be used as a marine gas oil with a reduced or minimized amount of additional processing. For example, the distillate boiling range fractions in FIG. 8 can be used as a DMA marine gas oil after distillation to form the distillate boiling range fraction.

FIG. 9 shows comparative data corresponding to modeled distillate boiling range fractions with comparable boiling ranges relative to FIG. 8 from three representative conventional crudes. Comparative distillate fraction A corresponds to a fraction derived from a light sweet crude. Comparative distillate fractions B and C correspond to fractions derived from heavy sour crudes. FIG. 9 further shows some specifications for forming a DMA marine gas oil according to ISO 8217.

As shown in FIG. 9, the comparative distillate fractions have weight ratios/volume ratios of naphthenes to aromatics that are less than 2.5, as well as sulfur contents of 0.3 wt % or more. Based on the sulfur content, any of the comparative fractions shown in FIG. 9 would require at least hydrotreating prior to use as a marine gas oil. Thus, the carbon intensity for a marine gas oil formed from one of these comparative fractions would be higher. The energy content of the comparative fractions is also lower, at 42.8 MJ/kg or less. Additionally, the comparative fractions have cetane index values below 50. The comparative fractions also have substantially higher densities and kinematic viscosities.

FIG. 10 shows modeled compositional features and properties for alternative distillate fractions formed from five of the seven shale crude oils. The alternative distillate fractions have an initial boiling point of 148° C. and a final boiling point of 464° C. so that a slightly greater portion of vacuum gas oil boiling range compounds is included in the fractions. This results in a modeled T10 distillation point of 185° C. to 195° C. and a T90 distillation point of 380° C. to 405° C. As shown in the modeled compositional values and properties in FIG. 10, the distillate fractions have an unexpectedly high weight ratio and/or volume ratio of naphthenes (cycloparaffins) to aromatics of 2.5 or more, or 3.0 or more, such as up to 8.0 or possibly still higher, while also including 5.0 wt % to 18 wt % aromatics, or 5.0 wt % to 15 wt %, or 5.0 wt % to 12 wt % (or 5.0 vol % to 18 vol % aromatics, or 5.0 vol % to 15 vol %, or 5.0 vol % to 12 vol %). The distillate fractions further have an unexpected combination of a low density at 15° C. of 810 kg/m³ to 840 kg/m³ (or 810 kg/m³ to 830 kg/m³); an energy content of 42.9 MJ/kg or greater; a low kinematic viscosity at 40° C. of 2.8 cSt to 3.2 cSt; a low sulfur content of 0.04 wt % to 0.10 wt %, or 0.05 wt % to 0.09 wt %; a low nitrogen content of 20 wppm or less, or 100 wppm or less, or 50 wppm or less, such as down to 5.0 wppm; and an acid number of less than 0.1 mg KOH/kg, or less than 0.08 mg KOH/kg.

FIG. 11 shows comparative data corresponding to modeled distillate boiling range fractions with comparable boiling ranges relative to FIG. 10 from three representative conventional crudes. Comparative distillate fraction A corresponds to a fraction derived from a light sweet crude. Comparative distillate fractions B and C correspond to fractions derived from heavy sour crudes. FIG. 11 further shows some specifications for forming a DMA marine gas oil according to ISO 8217.

As shown in FIG. 11, the comparative distillate fractions have weight ratios/volume ratios of naphthenes to aromatics that are less than 2.5, as well as sulfur contents of 0.3 wt % or more. Based on the sulfur content, any of the comparative fractions shown in FIG. 11 would require at least hydrotreating prior to use as a marine gas oil. Thus, the carbon intensity for a marine gas oil formed from one of these comparative fractions would be higher. Additionally, the comparative fractions have cetane index values below 50. The comparative fractions also have higher densities and kinematic viscosities.

Characterization of Shale Oil Fractions—Vacuum Gas Oils and Corresponding Fuel Oils

In some aspects, a vacuum gas oil fraction of a shale oil as described herein or a fraction can be used as a marine fuel oil or as a blending component for a marine fuel oil. The combination of low sulfur, high naphthene to aromatics ratio, low density, and low kinematic viscosity can allow a vacuum gas oil to be used as a marine fuel oil with reduced or minimized processing, such as possibly using the fraction as a fuel oil after distillation without further processing.

FIG. 12 and FIG. 13 show measured compositional features and properties for vacuum gas oil fractions formed from seven shale crude oils and/or shale crude oil blends. The vacuum gas oil cuts shown in FIG. 12 and FIG. 13 had a T10 distillation point of roughly 365° C.-380° C. and a T90 distillation point of roughly 500° C. to 525° C. As shown in FIG. 12 and FIG. 13, these vacuum gas oil fractions derived from shale crude oils and/or blends of shale crude oils had a relatively low density at 15° C. of 850 kg/m³ to 890 kg/m³, which indicates the presence of an unexpectedly high ratio of naphthenes to aromatics in the vacuum gas oil fractions. The unexpectedly high ratio of naphthenes to aromatics is further indicated by the high saturates content of the fractions of 75 w % or more. The vacuum gas oil fractions also had other unexpected combinations of properties, including an unexpectedly low kinematic viscosity; a sulfur content of less than 0.1 wt %, or less than 0.05 wt %, or less than 0.025 wt %; and a nitrogen content of less than 500 wppm, or less than 350 wppm.

FIG. 14 shows modeled data for the five vacuum gas oils shown in FIG. 12. The modeled vacuum gas oil fractions shown in FIG. 14 have an initial boiling point of 371° C. and a final boiling point of 538° C. This results in a modeled T10 distillation point of 385° C. to 395° C. and a T90 distillation point of 480° C. to 490° C. As shown in the modeled compositional values and properties in FIG. 14, the vacuum gas oil fractions have an unexpectedly high weight ratio/volume ratio of naphthenes (cycloparaffins) to aromatics of 1.0 or more, or 1.5 or more, or 2.0 or more, such as up to 6.0 or possibly still higher, while also including 8.0 wt % to 33 wt % aromatics, or 8.0 wt % to 22 wt %, or 10 wt % to 33 wt %, or 10 wt % to 22 wt % (or 8.0 vol % to 33 vol %, or 8.0 vol % to 22 vol %, or 10 vol % to 33 vol %, or 10 vol % to 22 vol %). Four of the five vacuum gas oil fractions have a naphthenes content of 40 wt %/40 vol % or more. The vacuum gas oil fractions further have an unexpected combination of a low density at 15° C. of 860 kg/m³ to 892 kg/m³ (or 860 kg/m³ to 882 kg/m); an energy content of 42.4 MJ/kg or greater, a low kinematic viscosity at 50° C. of 20 cSt to 30 cSt; a low sulfur content of 0.03 wt % to 0.20 wt %; a low nitrogen content of 1000 wppm or less, or 850 wppm or less, or 350 wppm or less, such as down to 30 wppm; a CCAI value of 760 to 785; a molar ratio of hydrogen to carbon of greater than 1.8; and an acid number of less than 0.15 mg KOH/kg, or less than 0.12 mg KOH/kg. Based on the sulfur content, density, and kinematic viscosity, the vacuum gas oil boiling range fractions in FIG. 14 can be used as a fuel oil with a reduced or minimized amount of additional processing. For example, the vacuum gas oil boiling range fractions in FIG. 14 can be used as a RMD 80 very low sulfur fuel oil according to ISO 8217 after distillation to form the distillate boiling range fraction.

FIG. 15 shows modeled values for selected high naphthene to aromatic ratio VGO fractions for 54 different shale crude oils and/or shale crude oil blends. As shown in FIG. 15, all of the high naphthene to aromatics ratio, low sulfur VGOs derived from shale crude oil sources have a lower sulfur content than the VGOs from conventional sources. The sulfur content for the shale VGO fractions is less than 0.33 wt %, for example, less than 0.30 wt %, or less than 0.25 wt %, or less than 0.20 wt %, or less than 0.15 wt %, or less than 0.10 wt %, and down to 0.004 wt %. Additionally, because the modeled VGO fractions have not been hydroprocessed, the weight ratio of aliphatic sulfur to total sulfur ranges from 0.29 to 1.00. Thus, the modeled VGO fractions have a weight ratio of aliphatic sulfur to total sulfur of greater than 0.2, or greater than 0.5, or greater than 0.6. This is in contrast to a hydroprocessed fraction, which would be expected to have a weight ratio of aliphatic sulfur to total sulfur of 0.1 or less.

As shown in FIG. 15, all of the high naphthene to aromatics ratio, low sulfur VGOs derived from shale crude oil sources have a lower nitrogen content than the conventional VGO fractions. The nitrogen content for the shale VGO fractions is less than 950 wppm, or less than 500 wppm, such as down to 20 wppm. Additionally, because the modeled VGO fractions have not been hydroprocessed, the weight ratio of basic nitrogen to total nitrogen ranges from 0.12 to 1.0. Thus, the modeled VGO fractions have a weight ratio of basic nitrogen to total nitrogen of greater than 0.1, or greater than 0.2, such as up to 1.0. This is in contrast to a hydroprocessed fraction, which would be expected to have a weight ratio of basic nitrogen to total nitrogen less than 0.05, or less than 0.01.

As shown in FIG. 1S, all of the high naphthene to aromatics ratio, low sulfur VGOs derived from shale crude oil sources also have a lower density at 15° C. than the conventional VGOs. The density for the shale VGO fractions is less than 890 kg/m³, or less than 860 kg/m³, or less than 845 kg/m³, such as down to 830 kg/m³.

Additionally, as shown in FIG. 15 all of the shale VGO fractions have a weight ratio of naphthenes to aromatics of 1.1 or greater, or greater than 1.5, or greater than 2.0, or greater than 3.0, such as up to 5.0 or possibly still higher.

The shale oil VGO fractions in FIG. 15 have still other potentially beneficial features. These features can include a naphthenes content of 10 wt % to 55 wt %, or 20 wt % to 55 wt %, or 35 wt % to 55 wt %, or 40 wt % to 55 wt %. Another feature can be an aromatics content of 34 wt % or less, or 26 wt % or less, or 20 wt % or less, or 15 wt % or less, such as down to 5.0 wt % or less, or possibly lower. Still other features can include a CCAI of 784 or less, or 770 or less, or 750 or less, such as down to 730 or less, or possibly still lower. The kinematic viscosity at 50° C. is less than 45.0 cSt for the shale VGOs, or less than 30.0 cSt, or less than 20.0 cSt, such as down to 10.0 cSt or less, or possibly still lower.

It is noted that while all of the 54 modeled shale fractions shown in FIG. 15 included a set of common features such as a sulfur content of 0.33 wt % or less, a density at 15° C. of 890 kg/m³ or less, a weight ratio of aliphatic to total sulfur of 0.2 or more, or a CCAI of 790 or less, other shale fractions have been discovered that include less than all of these features. FIG. 15 shows a comparison of 13 additional modeled shale fractions that differ from the 54 modeled shale VGO fractions in FIG. 15 based on one or more of sulfur content, density at 15° C., weight ratio of aliphatic to total sulfur, T10 distillation point, 190 distillation point, or CCAI. The 13 additional modeled shale fractions are shown in the middle column of FIG. 15. For the 13 additional modeled shale fractions, each of the fractions have at least one of the following properties: sulfur content above 0.33 wt %, density at 15° C. above 890 kg/m³, CCAI greater than 790, or a combination thereof.

As shown in FIG. 15, the 13 modeled additional shale fractions that have been discovered can have some properties that overlap with the 54 modeled shale VGO fractions from FIG. 15. However, it can also be seen that because the 13 modeled additional shale fractions do not have the combination of a sulfur content of 0.33 wt % or less, a density at 15° C. of 890 kg/m³ or less, a weight ratio of aliphatic to total sulfur of 0.2 or more, or a CCAI of 790 or less, the resulting average properties for the 13 modeled additional shale fractions can generally differ from the 54 modeled shale VGO fractions. For example, the 13 modeled additional shale fractions all have a kinematic viscosity at 50° C. of 36.3 cSt or more, which is near the top end of the range or above the range for the 54 modeled shale VGO fractions. Additionally, the 13 modeled additional shale fractions have a weight ratio of naphthenes to aromatics of 1.7 or less, which is near the bottom end of the range or below the range for the 54 modeled shale VGO fractions, and a nitrogen content of 857 or more, which is near the top end of the range or above the range for the 54 modeled shale VGO fractions.

FIG. 16 shows comparative data corresponding to modeled comparable vacuum gas oil boiling range fractions from three representative conventional crudes. Comparative vacuum gas oil fraction A corresponds to a fraction derived from a light sweet crude. Comparative vacuum gas oil fractions B and C correspond to fractions derived from heavy sour crudes. FIG. 15 also shows values for a hydrotreated vacuum gas oil fraction, as described in U.S. Pat. No. 8,999,011. FIG. 15 further shows some specifications for forming a RMD80 very low sulfur fuel oil according to ISO 8217.

As shown in FIG. 16, the comparative vacuum gas oil fractions have weight ratios/volume ratios of naphthenes to aromatics that are less than 1.5, or less than 1.0, as well as sulfur contents of 0.6 wt % or more. Based on the sulfur content, any of the comparative vacuum gas oil fractions shown in FIG. 16 would require at least hydrotreating prior to use as a very low sulfur fuel oil. Thus, the carbon intensity for a fuel oil formed from one of these comparative fractions would be higher. The energy content of the comparative fractions is also lower, at 42.2 MJ/kg or less. Additionally, the comparative fractions have a molar ratio of hydrogen to carbon of less than 1.8. The comparative fractions also have higher densities and kinematic viscosities.

Fuel Oil Blends Including Shale Vacuum Gas Oils

In the examples below, a variety of refinery fractions, renewable fractions and finished fuels are used as representative blending components for the formation of fuel blends. The fuel blends are formed by blending one or more low sulfur, high naphthene to aromatic ratio shale oil fractions with one or more of the refinery fractions, renewable fractions, or finished fuels.

As described above, vacuum gas oil fractions derived from low sulfur, high naphthene to aromatic shale oils can be used as fuel oils after reduced or minimized amounts of processing. This can have a corresponding effect of reducing or minimizing the carbon intensity of the resulting fuel due to refinery processing. In addition to using the low carbon intensity vacuum gas oils as fuel oils, the vacuum gas oils can also be blended with other low carbon intensity fractions to form still lower carbon intensity fuels.

As an example, distillates derived from biological sources can have a substantially lower carbon intensity, due in part to the consumption of carbon during the formation of the biomass. Blending a shale oil vacuum gas oil fraction with biodiesel and/or another renewable distillate can also provide unexpected synergistic advantages. For example, shale oil vacuum gas oils can also tend to have a relatively high pour point, so the biodiesel can also act as a pour point corrector. Biodiesel can also tend to have high solvency for asphaltenes, so blending biodiesel with a shale oil atmospheric resid can improve the ability to combine the resulting blended product with other resid fractions.

Another potential blending route for low carbon intensity vacuum gas oils can be to blend a vacuum gas oil with a conventional resid fraction to form low sulfur or very low sulfur fuel oils. The low density of these low carbon intensity vacuum gas oils means that they could be used to correct density in a blend, thereby expanding the use of high density component such as LCO, HCO, FCC bottoms, and visbreaker tars for making marine fuel oils. These low carbon intensity vacuum gas oils could also be used to correct sulfur, viscosity and CCAI in a blend, making it a versatile blend component. Additionally, the low carbon intensity vacuum gas oils have a viscosity at 50° C. about 10 times higher than a middle distillate. Thus, a low carbon intensity vacuum gas oil could be blended at a high level into a fuel oil and yet maintain a viscosity at 50° C.>10 cSt, which is the minimum viscosity preferred for optimal operation of the fuel injection system in a marine engine.

The first two columns of Table 5 show two types of biodiesels that were used as blend components for forming fuel oils and marine gas oils. The final two columns show two types of hydrotreated vegetable oils (HVOs) that were used as blend components for forming fuel oils.

TABLE 5 Vacuum Gas Oil Blend Components (Model) Biodiesel 1 Biodiesel 2 HVO1 HVO2 Density at 881.1 879.6 795.5 777.7 15° C. (kg/m3) KV50 (cSt) 3.5 3.734 3.076 2.299 Sulfur (ppm ~5 ~5 ~5 ~5 m/m) CCAI 828 824 746 741 BMCI 55 80 4 −2 TE 0 0 0 0 MCR (wt %) 0 0 0 0.4 Cloud Point −1 >1 10 −10 Pour Point (° C.) <−5 6 10 −10

Table 6 shows modeling results for blending vacuum gas oils from FIG. 14 with varying amounts of biodiesel or hydrotreated vegetable oil.

TABLE 6 Low Carbon Intensity Fuel Oil Blends Based on Vacuum Gas Oil ISO8217 90% HD5 + 10% 55% HD3 + 45% 90% HD5 + 10% 55% HD3 + 45% RMD80 Spec Biodiesel 1 Biodiesel 2 HVO 2 HVO 1 Density at 15° C. <990 878.7 885.4 868.3 0.8523 (kg/m3) Viscosity at <80 19.8 9.9 18.2 8.7 50° C. (cSt) Sulfur (wt %) <0.50 342 926 346 967 CCAI <860 781 803 772 768 BMCI — 32 55 27 21 TE — 0 0 0 0 N-Heptane — 0.00 0.00 0.00 0.00 Insolubles (wt %) MCR (wt %) <14 0.07 0.10 0.07 0.11 Pour Point (° C.) <30 ~30 ~23 ~30 ~25

As shown in Table 6, low carbon intensity fuel oils that satisfy the specifications for an RMD80 fuel oil can be formed with blends ranging from 10 vol % to 45 vol % in biodiesel, with the balance (55 vol % to 90 vol %) corresponding to low carbon intensity vacuum gas oil. Because of the low sulfur content and density of the low carbon intensity vacuum gas oil fractions, addition of 10 vol % of biodiesel or hydrotreated vegetable oil can result in a blend with satisfactory properties. Higher contents of biodiesel or hydrotreated vegetable oil, such as up to 45 vol %, can also be used due to the higher kinematic viscosity of the vacuum gas oil relative to a middle distillate fraction. Additionally, inclusion of 10 vol % or more of biodiesel or hydrotreated vegetable oil can be sufficient to form a blended fuel oil product with a pour point of 30 or less.

Characterization of Shale Oil Fractions—Vacuum Resids and Corresponding Fuel Oil Blends

Vacuum resid fractions correspond to fractions with T10 distillation points of roughly 500° C. or more. The kinematic viscosity of vacuum resid fractions derived from shale crude oil is typically too high to be used directly as a fuel oil. However, the other properties of a shale oil vacuum resids can allow the vacuum resids to serve as beneficial blending components.

For example, based on the low sulfur content, high energy content and low CCAI, shale oil vacuum resids can be beneficial fuel oil blend components to produce 0.1 wt % sulfur (ECA fuel oils) and 0.5 wt % sulfur fuel oils (VLSFO). The low density of the vacuum resids means that they can be used to correct density in a blend, thereby expanding the use of high density component such as LCO, HCO, FCC bottoms and visbreaker tars for making marine fuel oils.

FIG. 17 shows modeling of vacuum resid fractions for the five types of shale crude oils or shale crude oil blends shown in FIG. 3. The modeled vacuum resid fractions in FIG. 17 have an initial boiling point of 538° C. and a final boiling point greater than 600° C. As shown in FIG. 17, the vacuum resid fractions have a low density of 880 kg/m³ to 950 kg/m³, or 880 kg/m³ to 920 kg/m³. The vacuum resid fractions also have a low sulfur content of 0.35 wt % or less, or 0.1 wt % or less. The CCAI of the vacuum resids is also low, with values between 720 and 780, or between 720 and 750. Additionally, four of the five vacuum resids have an unexpectedly high weight ratio/volume ratio of naphthenes to aromatics of 1.0 or more, or 1.5 or more. For the four vacuum resids, this is due to having a naphthenes content of greater than 38 wt %/38 vol %, or greater than 40 wt %/40 vol %, and an unexpectedly low aromatics content of 20 wt % to 42 wt % (or 20 vol % to 42 vol %).

FIGS. 18 and 19 show modeled values for selected high naphthene to aromatic ratio vacuum resid (“VR”) fractions for 56 different shale crude oils and/or shale crude oil blends. As shown in FIG. 18, all of the high naphthene to aromatics ratio, low sulfur vacuum resid fractions derived from shale crude oil sources have a lower sulfur content than the vacuum resid fractions from conventional sources. The sulfur content for the shale vacuum resid fractions is less than 0.4 wt %, for example less than 0.37 wt %, or less than 0.25 wt %, or less than 0.20 wt %, or less than 0.15 wt %, and down to 0.01 wt %. Additionally, because the modeled vacuum resid fractions have not been hydroprocessed, the weight ratio of aliphatic sulfur to total sulfur ranges from 0.4 to 1.00. Thus, the modeled vacuum resid fractions have a weight ratio of aliphatic sulfur to total sulfur of greater than 0.2, or greater than 0.5, or greater than 0.6. This is in contrast to a hydroprocessed fraction, which would be expected to have a weight ratio of aliphatic sulfur to total sulfur of 0.1 or less.

As shown in FIG. 18, all of the high naphthene to aromatics ratio, low sulfur vacuum resids derived from shale crude oil sources have a lower nitrogen content than the conventional vacuum resid fractions. The nitrogen content for the shale vacuum resid fractions is less than 5000 wppm, or less than 2500 wppm, such as down to 50 wppm. Additionally, because the modeled vacuum resid fractions have not been hydroprocessed, the weight ratio of basic nitrogen to total nitrogen ranges from 0.037 to 1.0. Thus, the modeled vacuum resid fractions can have a weight ratio of basic nitrogen to total nitrogen of greater than 0.1, or greater than 0.2, such as up to 1.0. This is in contrast to a hydroprocessed fraction, which would all be expected to have a weight ratio of basic nitrogen to total nitrogen of less than 0.05, or less than 0.01.

As shown in FIG. 18, all of the high naphthene to aromatics ratio, low sulfur vacuum resid fractions derived from shale crude oil sources also have a lower density at 15° C. than the conventional vacuum resids. The density for the shale vacuum resid fractions is less than 950 kg/m³, or less than 900 kg/mA, or less than 890 kg/m³, such as down to 840 kg/m³.

Additionally, as shown in FIG. 18 all of the shale vacuum resid fractions have a weight ratio of naphthenes to aromatics of 0.35 or greater, or greater than 1.5, or greater than 2.0, or greater than 3.0, such as up to 4.0 and higher, or possibly still higher.

The shale oil vacuum resid fractions in FIG. 18 have still other potentially beneficial features. These features can include a naphthenes content of 20 wt % to 60 wt %, or 25 wt % to 60 wt %, or 35 wt % to 60 wt %, or 40 wt % to 60 wt %. Another feature can be an aromatics content of 70 wt % or less, or 50 wt % or less, or 30 wt % or less, or 20 wt % or less, such as down to 15.0 wt % or less, or possibly lower. Still other features can include a CCAI of 790 or less, or 750 or less, or 730 or less, such as down to 700 or less, or possibly still lower.

It is noted that while all of the 56 modeled shale fractions shown in FIG. 18 included a set of common features such as a sulfur content of 0.4 wt % or less, a density at 15° C. of 950 kg/m³ or less, a weight ratio of aliphatic to total sulfur of 0.2 or more, or a CCAI of 790 or less, other shale fractions have been discovered that include less than all of these features. FIG. 18 shows a comparison of 11 additional modeled shale fractions that differ from the 56 modeled shale vacuum resid fractions in FIG. 18 based on one or more of sulfur content, density at 15° C., weight ratio of aliphatic to total sulfur, or CCAI. The 11 additional modeled shale fractions are shown in the middle column of FIG. 18. For the 11 additional modeled shale fractions, each of the fractions have at least one of the following properties: sulfur content above 0.4 wt %, density at 15° C. above 950 kg/m³, or CCAI greater than 790, or a combination thereof.

As shown in FIG. 18, the 11 modeled additional shale fractions that have been discovered can have some properties that overlap with the 56 modeled shale vacuum resid fractions from FIG. 18. However, it can also be seen that because the 11 modeled additional shale fractions do not have the combination of a sulfur content of 0.4 wt % or less, a density at 15° C. of 950 kg/m³ or less, or CCAI of 790 or less, the resulting average properties for the 11 modeled additional shale fractions can generally differ from the 56 modeled shale vacuum resid fractions. For example, the 11 modeled additional shale fractions all have a kinematic viscosity at 50° C. of 10,606 cSt or more, which is near the top end of the range or above the range for the 56 modeled shale vacuum resid fractions. Additionally, the 11 modeled additional shale fractions have a weight ratio of naphthenes to aromatics of 0.36 or less, which is near the bottom end of the range or below the range for the 56 modeled shale VGO fractions, and a nitrogen content of 3868 wppm or more, which is near the top end of the range or above the range for the 56 modeled shale vacuum resid fractions.

Modeled examples of blending these fuel oil components with light cycle oil (LCO), gas oil and biodiesel to make finished ECA fuel oil and very low sulfur fuel oil (VLSFO) are given in Tables 7 and 8. In the LCO examples in Table 7, the density, CCAI and sulfur are simultaneously reduced in the blends containing VR Fuel Oil 1 or 3 from FIG. 17, which meets the VLSFO spec. In the gas oil examples, an ECA fuel oil product is made from VR Fuel Oils 2 and 5 because gas oil corrects the high pour point and viscosity of the fuel oil components while maintaining a sulfur content below 0.1 wt %.

TABLE 7 Vacuum Resid Blends 55% LCO, 35% LCO, 35% Gas 75% Gas 45% 60% Oil, 65% Oil, 25% ISO8217 VRFO1, VRFO3, VRFO2, VRFO5, RMD80 VLSFO, VLSFO, ECA, ECA, Spec high ratio low ratio low ratio high ratio Density at <990 901.8 936.9 8771 870.3 15° C. (kg/m3) KV50 (cSt) <80 28 202 112 11.6 Sulfur <0.50 0.4808 0.4950 0.0403 0.0593 (wt %) CCAI <860 798 805 752 784 BMCI — 42 54 25 31 TE — 6 4 0 0 N-Heptane — 0.15 0.16 0.15 0.02 Insolubles (wt %) MCR (wt %) <14 0.18 4.58 0.34 0.74 Pour Point <30 21 24 29 14 (° C.)

The biodiesel blends in Table 8 demonstrate that a wide range of biodiesel blend ratios is possible while having viscosity, pour point and sulfur content meets the requirements of an ECA or VLSFO product.

TABLE 8 Vacuum Resid Blends with Renewable Distillates 25% 50% 30% 70% Biodiesel, Biodiesel, Biodiesel, Biodiesel, 75% 50% 70% 30% ISO8217 VRFO5, VRFO1, VRFO3, VRFO3, RMD80 ECA, low ECA, high VLSFO, VLSFO, Spec ratio ratio low ratio low ratio Density at <990 907.0 880.9 926.9 0.8999 15° C. (kg/m3) KV50 (cSt) <80 366 33.0 298 13.8 Sulfur <0.50 0.0592 0.0148 0.2269 0.1004 (wt %) CCAI <860 768 774 790 810 BMCI — 46 50 59 71 TE — 0 0 0 0 N-Heptane — 0.05 0.11 0.14 0.06 Insolubles (wt %) MCR (wt %) <14 2.14 0.11 4.93 2.18 Pour Point <30 29 27 28 15 (° C.)

Properties for the LCO, gas oil, and biodiesel used in Tables 7 and 8 are provided in Table 9.

TABLE 9 Blend Components for Vacuum Resid Blends LCO Gas Oil Biodiesel 2 Density at 918.0 855.0 879.6 15° C. (kg/m3) KV50 (cSt) 4.2 4.27 3.734 Sulfur (ppm 8260 526 ~5 m/m) CCAI 858 795 824 BMCI 61.3 30 80 TE 17.5 0 0 MCR (wt %) 0.2 <0.001 0 Cloud Point — ? >1 Pour Point (° C.) −6 6 6

Additional Comparative Examples

The resid-containing, distillate, and vacuum gas oil compositions and blends described herein can be formed from selected types of crude oils, such as selected types of shale crude oils. Table 10 shows some comparative fractions that roughly correspond to vacuum gas oil boiling range fractions. The fractions shown in Table 10 were described in an article titled “Catalytic Solutions for Processing Shale Oils in the FCC” (www.digitalrefining.com, April 2014).

TABLE 10 Comparative VGO Fractions Eagle Ford Bakken Condensate VGO derived Crude Mid- Splitter from 85% 650° F. + Continent Bottoms Eagle Ford bottoms VGO API Gravity 36.6 30 23 24.7 Sulfur (wt %) 0.08 0.83 0.43 0.35 Aromatic ring 14.8 15.2 22.1 17.6 carbons Naphthene ring 19.4 9.8 17.3 20.3 carbons Paraffinic 65.8 75 60.6 62.1 carbons D2887 (° F.) T10 519 715 658 691 T50 735 862 844 848 T90 1006 1015 1135 1045

The Eagle Ford and Bakken fractions shown in Table 10 correspond to shale fractions, while the Mid-Continent VGO corresponds to a conventional fraction. The fractions in Table 10 roughly correspond to vacuum gas oil fractions, although the first column (splitter bottoms) includes some distillate. In Table 10, the aromatic carbons and naphthene carbons are reported based on the percentage of carbons that are present in ring structures, rather than providing a total weight percent for naphthenes or aromatics. However, this should not have a significant impact on the ratio of naphthenes to aromatics.

As shown in Table 10, all of the comparative vacuum gas oil fractions have naphthenic carbon to aromatic carbon ratios of less than 1.5. This is in contrast to the vacuum gas oil fractions shown in FIG. 14, where four of the five fractions have naphthenes to aromatics weight ratios of greater than 2.0. This further illustrates the unexpected nature of the atmospheric resid, vacuum resid, and vacuum gas oil compositions described herein.

Additional Embodiments

Embodiment 1. A vacuum gas oil boiling range fraction comprising a T10 distillation point of 360° C. or more, a T90 distillation point of 525° C. or less, a density at 15° C. of 890 kg/m³ or less, a sulfur content of 0.2 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 790 or less.

Embodiment 2. A fuel composition comprising 10 vol % to 45 vol % of a distillate fraction and 55 vol % to 90 vol % of the vacuum gas oil fraction of Embodiment 1.

Embodiment 3. The fuel composition of Embodiment 2, wherein the distillate fraction comprises a renewable distillate fraction, the renewable distillate fraction comprising one or more of biodiesel, fatty acid alkyl ester, and hydrotreated vegetable oil; or wherein the renewable distillate comprises a distillate made, processed or a combination thereof using a renewable energy source; or wherein the renewable distillate comprises a distillate formed from processing of biologically derived waste, or a combination thereof.

Embodiment 4. The vacuum gas oil boiling range fraction or fuel composition of any of the above Embodiments, wherein the vacuum gas oil boiling range fraction comprises a weight ratio of basic nitrogen to total nitrogen of 0.2 or more.

Embodiment 5. The vacuum gas oil boiling range fraction or fuel composition of any of the above Embodiments, wherein the vacuum gas oil boiling range fraction comprises a kinematic viscosity at 50° C. of 30 cSt or less, or wherein the vacuum gas oil boiling range fraction comprises a viscosity index of 80 or more, or a combination thereof.

Embodiment 6. The vacuum gas oil boiling range fraction or fuel composition of any of the above Embodiments, wherein the vacuum gas oil boiling range fraction comprises a weight ratio of naphthenes to aromatics of 1.0 or more, or wherein the vacuum gas oil boiling range fraction comprises 40 wt % or more of naphthenes.

Embodiment 7. The vacuum gas oil boiling range fraction or fuel composition of any of the above Embodiments, wherein the vacuum gas oil boiling range fraction comprises a nitrogen content of 850 wppm or less, or wherein the vacuum gas oil boiling range fraction comprises a pour point of 30° C. or more, or a combination thereof.

Embodiment 8. A fuel composition comprising 25 vol % to 75 vol % of a vacuum resid fraction and 25 vol % to 75 vol % of a distillate fraction, a cracked distillate fraction, or a combination thereof, the fuel composition comprising a density at 15° C. of 950 kg/m or less, a sulfur content of 0.5 wt % or less, a CCAI of 820 or less, and a pour point of 30° C. or less, the vacuum resid fraction comprising a density at 15° C. of 950 kg/m or less, a sulfur content of 0.35 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 780 or less.

Embodiment 9. The fuel composition of Embodiment 8, wherein the vacuum resid fraction comprises a weight ratio of naphthenes to aromatics of 1.0 or more, or wherein the vacuum resid fraction comprises 38 wt % or more of naphthenes, or a combination thereof.

Embodiment 10. The fuel composition of Embodiment 8 or 9, wherein the distillate fraction comprises a renewable distillate fraction, the fuel composition comprising 25 vol % to 70 vol % of the renewable distillate fraction and 30 vol % to 75 vol % of the vacuum resid fraction.

Embodiment 11. The fuel composition of any of Embodiments 8-10, wherein the vacuum resid fraction comprises 5.0 wppm or more of sodium, 10 wppm or more of calcium, a weight ratio of basic nitrogen to total nitrogen of 0.2 or more, or a combination thereof.

Embodiment 12. A marine fuel composition comprising a T10 distillation point of 150° C. to 230° C., a T90 distillation point of 350° C. to 425° C., a kinematic viscosity at 40° C. of 2.0 cSt to 4.0 cSt, a sulfur content of 0.07 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a cetane index of 45 or more.

Embodiment 13. The marine fuel composition of Embodiment 12, wherein the marine fuel composition comprises a weight ratio of naphthenes to aromatics of 2.5 or more, a naphthenes content of 40 wt % or more, or a combination thereof.

Embodiment 14. The marine fuel composition of Embodiment 12 or 13, wherein the marine fuel composition comprises a nitrogen content of 200 wppm or less, or wherein the marine fuel composition comprises an acid number of 0.02 to 0.07 mg KOH/g; or wherein the marine fuel composition comprises a pour point of 0° C. or less; or wherein the marine fuel composition comprises a density at 15° C. of 810 kg/m³ to 835 kg/m³; or a combination thereof.

Embodiment 15. Use of a composition comprising a vacuum gas oil boiling range fraction, a fuel composition, or a marine fuel composition according to any of the above Embodiments as a fuel in an engine, a furnace, a burner, a combustion device, or a combination thereof.

Embodiment 16. Use of the composition of Embodiment 15, wherein the vacuum gas oil boiling range fraction has not been exposed to hydroprocessing conditions.

Embodiment 17. A method for forming a fuel composition, comprising fractionating a whole crude or crude fraction to form a vacuum gas oil boiling range fraction or a marine fuel composition according to any of Embodiments 1, 4-7, or 12-14.

Embodiment 18. A method for forming a fuel composition, comprising: fractionating a whole crude or crude fraction to form a vacuum gas oil fraction comprising a T10 distillation point of 360° C. or more, a T90 distillation point of 525° C. or less, a density at 15° C. of 890 kg/m³ or less, a sulfur content of 0.2 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 790 or less.

Embodiment 19. The method of Embodiment 18, further comprising blending 10 vol % to 50 vol % of a resid-containing fraction with 50 vol % to 90 vol % of the vacuum gas oil fraction to form a blended fuel oil composition comprising a sulfur content of 0.5 wt % or less.

Embodiment 20. The method of Embodiment 18, further comprising blending 10 vol % to 45 vol % of a distillate fraction with 55 vol % to 90 vol % of the vacuum gas oil fraction to form a blended fuel composition comprising a sulfur content of 0.5 wt % or less.

Embodiment 21. The method of any of Embodiments 18-20, wherein the distillate fraction comprises a renewable distillate fraction.

Embodiment 22. The method of any of Embodiments 18-21, wherein the blended fuel composition comprises a pour point of 30° C. or less.

Embodiment 23. A method for forming a residual fuel or fuel blending product, comprising blending 25 vol % to 75 vol % of a vacuum resid fraction and 25 vol % to 75 vol % of a distillate fraction, a cracked distillate fraction, or a combination thereof, the fuel composition comprising a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.5 wt % or less, a CCAI of 820 or less, and a pour point of 30° C. or less, the vacuum resid fraction comprising a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.35 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 780 or less.

Embodiment 24. The method of Embodiment 23, wherein the distillate fraction comprises a renewable distillate fraction, the fuel composition comprising 25 vol % to 70 vol % of the renewable distillate fraction and 30 vol % to 75 vol % of the vacuum resid fraction.

Embodiment 25. A method for forming a fuel composition, comprising: fractionating a whole crude or crude fraction to form a fraction comprising a T10 distillation point of 150° C. to 230° C., a T90 distillation point of 350° C. to 425° C., a kinematic viscosity at 40° C. of 2.0 cSt to 4.0 cSt, a sulfur content of 0.07 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a cetane index of 45 or more.

PCT/EP Clauses:

1. A vacuum gas oil boiling range fraction comprising a T10 distillation point of 350° C. or more, a T90 distillation point of 525° C. or less, a density at 15° C. of 890 kg/m³ or less, a sulfur content of 0.3 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 790 or less.

2. The vacuum gas oil boiling range fraction of clause 1, wherein the vacuum gas oil boiling range fraction comprises a weight ratio of basic nitrogen to total nitrogen of 0.2 or more.

3. The vacuum gas oil boiling range fraction of clauses 1-2, wherein the vacuum gas oil boiling range fraction comprises a kinematic viscosity at 50° C. of 45 cSt or less, or wherein the vacuum gas oil boiling range fraction comprises a viscosity index of 80 or more, or a combination thereof.

4. The vacuum gas oil boiling range fraction of clauses 1-3, wherein the vacuum gas oil boiling range fraction comprises a weight ratio of naphthenes to aromatics of 1.0 or more.

5. The vacuum gas oil boiling range fraction of clauses 1-4, wherein the vacuum gas oil boiling range fraction comprises 40 wt % or more of naphthenes.

6. The vacuum gas oil boiling range fraction of clauses 1-5, wherein the vacuum gas oil boiling range fraction comprises a nitrogen content of 950 wppm or less, or wherein the vacuum gas oil boiling range fraction comprises a pour point of 20° C. or more, or a combination thereof.

7. Use of a composition comprising the vacuum gas oil boiling range fraction of clauses 1-6 as a fuel in an engine, a furnace, a burner, a combustion device, or a combination thereof.

8. Use of the composition of clause 7, wherein the vacuum gas oil boiling range fraction has not been exposed to hydroprocessing conditions.

9. A fuel composition comprising 10 vol % to 45 vol % of a distillate fraction and 55 vol % to 90 vol % of an vacuum gas oil fraction, wherein the vacuum gas oil fraction comprises a T90 distillation point of 525° C. or less, a density at 15° C. of 890 kg/m³ or less, a sulfur content of 0.3 wt % or less, and a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more.

10. The fuel composition of clause 9, wherein the vacuum gas oil fraction comprises a kinematic viscosity at 50° C. of 15 cSt or more, a CCAI of 790 or less, or a combination thereof.

11. The fuel composition of clauses 9-10, wherein the distillate fraction comprises a renewable distillate fraction.

12. The fuel composition of clause 11, wherein the renewable distillate fraction comprises one or more of biodiesel, fatty acid alkyl ester, and hydrotreated vegetable oil; or wherein the renewable distillate comprises a distillate made, processed or a combination thereof using a renewable energy source; or wherein the renewable distillate comprises a distillate formed from processing of biologically derived waste, or a combination thereof.

13. The fuel composition of clauses 9-12, wherein the fuel composition comprises a pour point of 30° C. or less.

14. The fuel composition of clauses 9-13, wherein the vacuum gas oil fraction comprises a naphthenes to aromatics ratio of 1.0 or more, or wherein the vacuum gas oil fraction comprises 40 wt % or more of naphthenes, or a combination thereof.

15. Use of a composition comprising the fuel composition of clauses 9-14 as a fuel in an engine, a furnace, a burner, a combustion device, or a combination thereof.

16. A method for forming a fuel composition, comprising: fractionating a whole crude or crude fraction to form a vacuum gas oil fraction comprising a T10 distillation point of 350° C. or more, a T90 distillation point of 525° C. or less, a density at 15° C. of 890 kg/m³ or less, a sulfur content of 0.3 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 790 or less.

17. The method of clause 16, further comprising blending 10 vol % to 50 vol % of a resid-containing fraction with 50 vol % to 90 vol % of the vacuum gas oil fraction to form a blended fuel oil composition comprising a sulfur content of 0.5 wt % or less.

18. The method of clauses 16-17, further comprising blending 10 vol % to 45 vol % of a distillate fraction with 55 vol % to 90 vol % of the vacuum gas oil fraction to form a blended fuel composition comprising a sulfur content of 0.5 wt % or less.

19. The method of clauses 18, wherein the distillate fraction comprises a renewable distillate fraction.

20. The method of clauses 18-19, wherein the blended fuel composition comprises a pour point of 30° C. or less.

21. A vacuum resid boiling range fraction comprising a T10 distillation point of 500° C. or more, a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.4 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 790 or less.

22. The vacuum resid boiling range fraction of clause 21 including a weight ratio of naphthenes to aromatics of 0.35 or more, 24 wt % or more of naphthenes, or a combination thereof.

23. The vacuum resid boiling range fraction of clauses 21-22 including 2.0 wppm or more of sodium, 5 wppm or more of calcium, a weight ratio of basic nitrogen to total nitrogen of 0.2 or more, or a combination thereof.

24. A fuel composition comprising: 25 vol % to 75 vol % of a vacuum resid fraction and 25 vol % to 75 vol % of a distillate fraction, a cracked distillate fraction, or a combination thereof, wherein the fuel composition comprises a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.5 wt % or less, a CCAI of 820 or less, and a pour point of 30° C. or less, and wherein the vacuum resid fraction comprises a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.4 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 790 or less.

25. The fuel composition of clause 24, wherein the vacuum resid fraction comprises a weight ratio of naphthenes to aromatics of 0.35 or more, or wherein the vacuum resid fraction comprises 24 wt % or more of naphthenes, or a combination thereof.

26. The fuel composition of clauses 24-25, wherein the fuel composition comprises a sulfur content of 0.1 wt % or less, or wherein the vacuum resid fraction comprises a sulfur content of 0.1 wt % or less, or a combination thereof.

27. The fuel composition of clauses 24-26, wherein the fuel composition comprises a pour point of 30° C. or less.

28. The fuel composition of clauses 24-27, wherein the distillate fraction comprises a renewable distillate fraction, the fuel composition comprising 25 vol % to 70 vol % of the renewable distillate fraction and 30 vol % to 75 vol % of the vacuum resid fraction.

29. The fuel composition of clauses 24-28, wherein the vacuum resid fraction comprises 2.0 wppm or more of sodium, 5 wppm or more of calcium, a weight ratio of basic nitrogen to total nitrogen of 0.2 or more, or a combination thereof.

30. Use of a composition comprising the fuel composition of clauses 24-29 as a fuel in an engine, a furnace, a burner, a combustion device, or a combination thereof.

31. A method for forming a residual fuel or fuel blending product comprising: blending 25 vol % to 75 vol % of a vacuum resid fraction and 25 vol % to 75 vol % of a distillate fraction, a cracked distillate fraction, or a combination thereof, wherein the fuel composition comprises a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.5 wt % or less, a CCAI of 820 or less, and a pour point of 30° C. or less, and wherein the vacuum resid fraction comprises a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.35 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 780 or less.

32. The method of clause 31, wherein the distillate fraction comprises a renewable distillate fraction, and wherein the fuel composition comprises 25 vol % to 70 vol % of the renewable distillate fraction and 30 vol % to 75 vol % of the vacuum resid fraction.

33. A marine fuel composition comprising a T10 distillation point of 150° C. to 230° C., a T90 distillation point of 350° C. to 425° C., a kinematic viscosity at 40° C. of 2.0 cSt to 4.0 cSt, a sulfur content of 0.07 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a cetane index of 45 or more.

34. The marine fuel composition of clause 33, wherein the marine fuel composition comprises a flash point of 60° C. or more, a density at 15° C. of 810 kg/m³ to 835 kg/m³, a kinematic viscosity at 40° C. of 2.5 cSt to 3.2 cSt, or a combination thereof.

35. The marine fuel composition of clauses 33-34, wherein the marine fuel composition comprises a weight ratio of naphthenes to aromatics of 2.5 or more, a naphthenes content of 40 wt % or more, or a combination thereof.

36. The marine fuel composition of clauses 33-35, wherein the marine fuel composition comprises a nitrogen content of 200 wppm or less; or wherein the marine fuel composition comprises an acid number of 0.02 to 0.07 mg KOH/g; or wherein the marine fuel composition comprises a pour point of 0° C. or less; or a combination thereof.

37. Use of a composition comprising the marine fuel composition of clauses 33-36 as a fuel in an engine, a furnace, a burner, a combustion device, or a combination thereof.

38. Use of the composition of clause 37, wherein the marine fuel composition has not been exposed to hydroprocessing conditions.

39. A method for forming a fuel composition, comprising: fractionating a whole crude or crude fraction to form a fraction comprising a T10 distillation point of 150° C. to 230° C., a T90 distillation point of 350° C. to 425° C., a kinematic viscosity at 40° C. of 2.0 cSt to 4.0 cSt, a sulfur content of 0.07 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a cetane index of 49 or more.

While the present invention has been described and illustrated by reference to particular embodiments, those of ordinary skill in the art will appreciate that the invention lends itself to variations not necessarily illustrated herein. For this reason, then, reference should be made solely to the appended claims for purposes of determining the true scope of the present invention. 

What is claimed is:
 1. A vacuum gas oil boiling range fraction comprising a T10 distillation point of 350° C. or more, a T90 distillation point of 525° C. or less, a density at 15° C. of 890 kg/m³ or less, a sulfur content of 0.3 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 790 or less, wherein the vacuum gas oil boiling range fraction has not been exposed to hydroprocessing conditions.
 2. The vacuum gas oil boiling range fraction of claim 1, wherein the vacuum gas oil boiling range fraction comprises a weight ratio of basic nitrogen to total nitrogen of 0.2 or more.
 3. The vacuum gas oil boiling range fraction of claim 1, wherein the vacuum gas oil boiling range fraction comprises a kinematic viscosity at 50° C. of 45 cSt or less, or wherein the vacuum gas oil boiling range fraction comprises a viscosity index of 80 or more, or a combination thereof.
 4. The vacuum gas oil boiling range fraction of claim 1, wherein the vacuum gas oil boiling range fraction comprises a weight ratio of naphthenes to aromatics of 1.0 or more.
 5. The vacuum gas oil boiling range fraction of claim 1, wherein the vacuum gas oil boiling range fraction comprises 40 wt % or more of naphthenes.
 6. The vacuum gas oil boiling range fraction of claim 1, wherein the vacuum gas oil boiling range fraction comprises a nitrogen content of 950 wppm or less, or wherein the vacuum gas oil boiling range fraction comprises a pour point of 20° C. or more, or a combination thereof.
 7. The vacuum gas oil boiling range composition of claim 1, wherein the vacuum gas oil boiling range composition is used as a fuel in an engine, a furnace, a burner, a combustion device, or a combination thereof.
 8. A fuel composition comprising 10 vol % to 45 vol % of a distillate fraction and 55 vol % to 90 vol % of an vacuum gas oil fraction, wherein the vacuum gas oil fraction comprises a T90 distillation point of 525° C. or less, a density at 15° C. of 890 kg/m³ or less, a sulfur content of 0.3 wt % or less, and a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, wherein the vacuum gas oil fraction has not been exposed to hydroprocessing conditions.
 9. The fuel composition of claim 8, wherein the vacuum gas oil fraction comprises a kinematic viscosity at 50° C. of 15 cSt or more, a CCAI of 790 or less, or a combination thereof.
 10. The fuel composition of claim 8, wherein the distillate fraction comprises a renewable distillate fraction.
 11. The fuel composition of claim 8, wherein the renewable distillate fraction comprises one or more of biodiesel, fatty acid alkyl ester, and hydrotreated vegetable oil; or wherein the renewable distillate comprises a distillate made, processed or a combination thereof using a renewable energy source; or wherein the renewable distillate comprises a distillate formed from processing of biologically derived waste, or a combination thereof.
 12. The fuel composition of claim 8, wherein the fuel composition comprises a pour point of 30° C. or less.
 13. The fuel composition of claim 8, wherein the vacuum gas oil fraction comprises a naphthenes to aromatics ratio of 1.0 or more, or wherein the vacuum gas oil fraction comprises 40 wt % or more of naphthenes, or a combination thereof.
 14. The fuel composition of claim 8, wherein the fuel composition is used as a fuel in an engine, a furnace, a burner, a combustion device, or a combination thereof.
 15. A method for forming a fuel composition, comprising: fractionating a whole crude or crude fraction to form a vacuum gas oil fraction comprising a T10 distillation point of 350° C. or more, a T90 distillation point of 525° C. or less, a density at 15° C. of 890 kg/m³ or less, a sulfur content of 0.3 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 790 or less, wherein the vacuum gas oil fraction has not been exposed to hydroprocessing conditions.
 16. The method of claim 15, further comprising blending 10 vol % to 50 vol % of a resid-containing fraction with 50 vol % to 90 vol % of the vacuum gas oil fraction to form a blended fuel oil composition comprising a sulfur content of 0.5 wt % or less.
 17. The method of claim 15, further comprising blending 10 vol % to 45 vol % of a distillate fraction with 55 vol % to 90 vol % of the vacuum gas oil fraction to form a blended fuel composition comprising a sulfur content of 0.5 wt % or less.
 18. The method of claim 17, wherein the distillate fraction comprises a renewable distillate fraction.
 19. The method of claim 17, wherein the blended fuel composition comprises a pour point of 30° C. or less.
 20. A vacuum resid boiling range fraction comprising a T10 distillation point of 500° C. or more, a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.4 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 790 or less, wherein the vacuum resid boiling range fraction has not been exposed to hydroprocessing conditions.
 21. The vacuum resid boiling range fraction of claim 20 including a weight ratio of naphthenes to aromatics of 0.35 or more, 24 wt % or more of naphthenes, or a combination thereof.
 22. The vacuum resid boiling range fraction of claim 20 including 2.0 wppm or more of sodium, 5 wppm or more of calcium, a weight ratio of basic nitrogen to total nitrogen of 0.2 or more, or a combination thereof.
 23. A fuel composition comprising: 25 vol % to 75 vol % of a vacuum resid fraction and 25 vol % to 75 vol % of a distillate fraction, a cracked distillate fraction, or a combination thereof, wherein the fuel composition comprises a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.5 wt % or less, a CCAI of 820 or less, and a pour point of 30° C. or less, and wherein the vacuum resid fraction comprises a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.4 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 790 or less, wherein the vacuum resid fraction has not been exposed to hydroprocessing conditions.
 24. The fuel composition of claim 23, wherein the vacuum resid fraction comprises a weight ratio of naphthenes to aromatics of 0.35 or more, or wherein the vacuum resid fraction comprises 24 wt % or more of naphthenes, or a combination thereof.
 25. The fuel composition of claim 23, wherein the fuel composition comprises a sulfur content of 0.1 wt % or less, or wherein the vacuum resid fraction comprises a sulfur content of 0.1 wt % or less, or a combination thereof.
 26. The fuel composition of claim 23, wherein the fuel composition comprises a pour point of 30° C. or less.
 27. The fuel composition of claim 23, wherein the distillate fraction comprises a renewable distillate fraction, the fuel composition comprising 25 vol % to 70 vol % of the renewable distillate fraction and 30 vol % to 75 vol % of the vacuum resid fraction.
 28. The fuel composition of claim 23, wherein the vacuum resid fraction comprises 2.0 wppm or more of sodium, 5 wppm or more of calcium, a weight ratio of basic nitrogen to total nitrogen of 0.2 or more, or a combination thereof.
 29. The fuel composition of claim 23, wherein the fuel composition is used as a fuel in an engine, a furnace, a burner, a combustion device, or a combination thereof.
 30. A method for forming a residual fuel or fuel blending product comprising: blending 25 vol % to 75 vol % of a vacuum resid fraction and 25 vol % to 75 vol % of a distillate fraction, a cracked distillate fraction, or a combination thereof, wherein the fuel composition comprises a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.5 wt % or less, a CCAI of 820 or less, and a pour point of 30° C. or less, and wherein the vacuum resid fraction comprises a density at 15° C. of 950 kg/m³ or less, a sulfur content of 0.35 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a CCAI of 780 or less, wherein the vacuum resid fraction has not been exposed to hydroprocessing conditions.
 31. The method of claim 30, wherein the distillate fraction comprises a renewable distillate fraction, and wherein the fuel composition comprises 25 vol % to 70 vol % of the renewable distillate fraction and 30 vol % to 75 vol % of the vacuum resid fraction.
 32. A marine fuel composition comprising a T10 distillation point of 150° C. to 230° C., a T90 distillation point of 350° C. to 425° C., a kinematic viscosity at 40° C. of 2.0 cSt to 4.0 cSt, a sulfur content of 0.07 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a cetane index of 45 or more, wherein the marine fuel composition has not been exposed to hydroprocessing conditions.
 33. The marine fuel composition of claim 32, wherein the marine fuel composition comprises a flash point of 60° C. or more, a density at 15° C. of 810 kg/m³ to 835 kg/m³, a kinematic viscosity at 40° C. of 2.5 cSt to 3.2 cSt, or a combination thereof.
 34. The marine fuel composition of claim 32, wherein the marine fuel composition comprises a weight ratio of naphthenes to aromatics of 2.5 or more, a naphthenes content of 40 wt % or more, or a combination thereof.
 35. The marine fuel composition of claim 32, wherein the marine fuel composition comprises a nitrogen content of 200 wppm or less; or wherein the marine fuel composition comprises an acid number of 0.02 to 0.07 mg KOH/g; or wherein the marine fuel composition comprises a pour point of 0° C. or less; or a combination thereof.
 36. The marine fuel composition of claim 32, wherein the marine fuel composition is used as a fuel in an engine, a furnace, a burner, a combustion device, or a combination thereof.
 37. A method for forming a fuel composition, comprising: fractionating a whole crude or crude fraction to form a fraction comprising a T10 distillation point of 150° C. to 230° C., a T90 distillation point of 350° C. to 425° C., a kinematic viscosity at 40° C. of 2.0 cSt to 4.0 cSt, a sulfur content of 0.07 wt % or less, a weight ratio of aliphatic sulfur to total sulfur of 0.2 or more, and a cetane index of 49 or more, wherein the fuel composition has not been exposed to hydroprocessing conditions. 